Energy Transfer LP (ET) 2006 Q2 法說會逐字稿

Welcome to the second quarter 2006 Southern Union Company earnings conference call. [OPERATOR INSTRUCTIONS] As a reminder, ladies and gentlemen, this conference is being recorded. I would now like to turn the presentation over to your host for today's conference Mr. Jack Walsh, Director of Investor Relations. Please proceed, sir.

Thank you, and welcome to Southern Union's second quarter 2006 earnings call and webcast. Presenting on today's call will be George Lindemann, Chairman, President, and CEO; Julie Edwards, Senior Vice President and CFO; Rob Bond, Senior Vice President of our Pipeline Operations; and Craig Strehl, Senior Vice President of Gas Services. A replay of this call will be available for one week by dialing 888-286-8010, and entering passcode 50138577. A replay of the webcast will be accessible through our website at www.sug.com. If you have not yet received a copy of the earnings release issued today, you may request a copy by calling 800-321-7423, or you may obtain it through our website.

Today we will be discussing results for the second quarter of 2006, significant events, and outlook. Following our presentation we will be happy to address your questions. If you have any further questions at the end of the call please contact me directly at 800-321-7423.

Before beginning, I would like to caution that you many of the statements contained in our call may be based on management's current expectations, estimates, and projections about the industry in which the Company operates. These statements are not guarantees of future performance and involve risks. The Company undertakes no obligation to update publicly any forward-looking statements as a result of new information, future events, or otherwise. Such statements are intended to be covered by the Safe Harbor provisions of the Securities Act of 1933 and the Securities Exchange Act of 1934. I would also refer you to the cautionary statement regarding forward-looking information and our earnings release. I will now turn the call over to Mr. George Lindemann. Mr. Lindemann.

Thank you, and good afternoon. The second quarter of 2006 was a solid one operationally for Southern Union. Our transportation and midstream segments both performed exceptionally well as evidenced by the strong results. Additionally, we have made several strides forward as it relates to its ongoing transformation of the Company. Over the last few months, we have placed phase 1 and phase 2 expansion of our Lake Charles LNG terminal into service. We are also pleased to have -- to announce two other significant projects during the quarter, both of which Rob Bond will describe in further details. The first is another major project in our LNG terminal, and the second is an expansion of our trunk line gas company pipeline in east Texas.

Recently the Rhode Island division of the public utilities and carriers issued an order approving the sale of Rhode Island assets to National. In Pennsylvania an administrative law judge has recommended approval of the sale of PG Energy assets to UGI Corporation. We expect the Pennsylvania transaction to go before the Pennsylvania Public Utility Commission later this month. The final highlight that I would like to give you is that we have completed our near-term hedging program at Southern Union services. And we have been able to hedge our remaining equity volumes for 2006 and 2007. These additional hedges were done at a net average price of 11.03 per mmbtu in 2006 and 10.57 per mmbtu in 2006.

Now I would like to turn the call over to Julie Edwards, our CFO to give you an overview of the quarter. Following Julie, Rob Bond will give you an overview of the pipeline business, then Craig Strehl will give you an overview of the midstream business and details of the hedging that we have put in place. After that I'd be happy to answer any questions that you might have. Julie.

Thank you, George, and good afternoon. As you've seen in our press release, we've reported net earnings from continuing operations of $16.3 million, or $0.10 per diluted share on earnings before interest and taxes including CCE H of 87.2 million. This compares to net earnings from continuing operations of 17.6 million, or $0.12 per diluted share on EBIT of 52 million in the same period last year. The current quarter's results are a bit difficult to compare to the prior year due to the interest expense and debt amortization related to our $1.6 billion bridge loan. Adjusting for our expected $1.1 billion repayment of the bridge following the closing of the LDC sales the Company earned 29.3 million, or $0.21 per diluted share for the quarter.

We hope this presentation gives our investors a more accurate picture of what the Company would look like after closing the LDC sale and the related repayment of the bridge. Our operating revenues for the quarter were $552.4 million, an increase of 357.1 million compared to 195.2 million in the prior year. This increase is reflective of the addition of SUGS on March 1. Including our discontinued operations, the Company earned 9.4 million, or $0.08 per diluted share. Discontinued operations, which include our Pennsylvania and Rhode Island distribution assets, accounted for a net loss of 2.6 million, or $0.02 per diluted share.

In terms of a breakdown of these results, our transportation and storage segment, including our investment in CCEH had earnings before interest and taxes of 76 million, up 14.4 million from the prior year. This increase is attributable to Panhandle Energy which includes Panhandle eastern pipeline, trunk line pipeline, trunk line LNG, and the Sea Robin operations. These were up 18.8 million on an earnings before interest and taxes basis. This increase came primarily from a 13.5 million increase in LNG revenue, largely a result of the phase 1 expansion of our LNG facility which was placed in service on April 5, of this year. Additionally, panhandle benefited from higher transportation and storage revenue of 7 million as a result of higher average reservation rates of 4.7 million, increased parking revenues of 2.7 million, and higher storage revenues of 1.8 million, offset somewhat by lingering hurricane-related impacts on Sea Robin of 2.2 million.

Equity earnings from our share of cross-country energy were down 4.4 million year-over-year, primarily related to lower transportation rates on transwestern, coupled with system balancing expense and higher operating expenses primarily related to the May 2005 San Juan expansion. Our newly acquired gathering and processing segment generated 17.9 million in EBIT for the second quarter. In addition we received 21.8 million in cash from the second quarter settlement of the natural gas put options we purchased last December. This amount is not included in the segment EBIT. The true operating cash flow of the segment is their EBIT plus depreciation plus the cash settlement of the put options plus or minus any noncash income or loss booked to adjust the time value portion of the hedge. For the second quarter this totalled 54.4 million.

Our ongoing distribution business generated a seasonal loss before interest and taxes of 6.4 million for the quarter, compared to a loss of 5.5 million one year ago. The primary driver of performance for the distribution segment continues to be weather, which is one of the reasons why we requested a straight fixed variable rate design in our pending Missouri rate case to help mitigate the impact of weather on our earnings and cash flow. Interest expense was up 33.1 million compared to the prior year, and is primarily due to 26.4 million of bridge loan interest and related cost amortization. We plan to repay approximately 1.1 billion of the bridge lone with the net proceeds from the closings of our LDC assets this quarter. This repayment approximates net interest savings of 6.4 million per month or 19.2 million for the quarter.

During the quarter, we invested approximately 76 million in our operations. Gross capital accounted for 42 million and maintenance capital was 34 million. Panhandle Energy spent 48 million, 28 million of which was for growth and 20 million was for maintenance. Approximately 14 million was reinvested in SUGS with growth accounting for approximately 11 million. We have reinvested approximately 14 million in our remaining distribution business with growth capital of approximately 3 million. Our capital outlook for 2006 has sustaining capital of approximately 140 million. Of this, Panhandle represents approximately 85 million, continuing distribution businesses represent approximately 30 million. Corporate is approximately 10 million, and SUGS is approximately 15 million. The SUBs maintenance number is higher than previously reported as we have conformed our accounting policy. Growth capital is not included in the above figures. We expect to spend approximately 215 million at Panhandle and 25 to 30 million at SUGS on growth/profit projects for 2006.

For 2006, we still expect our annualized pro forma EPS from continuing ops to be in the range of $1.70 to $1.90 per share. We expect reported GAAP earnings, excluding any further charges related to the sales of our LDCs, to be in the range of $1.70 to $1.90 per share. From an EBITDA standpoint we expect the retained LDCs to be in the range of 70 to 80 million. For our transportation segment, specifically Panhandle energy, we expect EBITDA in the range of 315 to 335 million. This represents an increase of 15 million over each end of the range from our last call. For SUGS we expect annual EBITDA in the range of 200 to 220 million, including the cash value of the gas put options. We expect pretax earnings from CrossCountry energy to now be in the range of 50 to 60 million. This represents a decrease of 10 million to each side of the range, primarily due to market conditions that exist on transwestern's western side of the system. The capacity that was turned back from one of our large shippers last year has been selling at a lower price than originally anticipated. With that I'll turn the call over to Rob Bond, Senior Vice President of our Integrated Pipeline Operations.

Thank you, Julie. Good afternoon, everyone. As Julie mentioned, the transportation and storage segment of our business performed very well for the quarter, largely driven by LNG and continued strength at Panhandle. As George indicated earlier we completed and placed our LNG phase 2 expansion in service on July the 8th. To remind everyone, phase 2 increased our send out capacity of 1.8 bcf per day with peak capacity of 2.1 bcf per day. Phase 2 will result in annual EBIT of 15 to $20 million. As you recall, the annual EBIT from phase 1 is 28 million.

To finish our discussion on LNG, we continue to move forward with the infrastructure enhancement project, or IEP, as we call it. This project adds ambient air vaporization and NGL extraction capabilities to the terminal. This project is expected to cost $250 million and is fully contracted to BG under long-term agreements. We expect this project to contribute 30 to $35 million of annual EBIT once it is completed in the second half of 2008. trunk line LNG and BG have also agreed to extend the terminal and pipeline service agreements through 2028, which represents a five-year contract extension.

A new project that's been announced since our last call is the trunk line gas company field zone expansion project, formally known as the north Texas expansion. This project will expand our system from east Texas into Louisiana. We currently have contracts signed with anchor shippers for 510 million cubic feet per day. The project is estimated to cost between 150 and 160 million and generate annual EBIT between 18 and $25 million. We're on schedule for a late third quarter filing with FERC and expect to have have the project in service by late 2007.

Another project that continues to progress is the Florida gas phase 7 expansion. This project will add 100 million cubic feet per day of additional capacity for customers in the Orlando area. We plan to build approximately 33 miles of pipeline looping in several segments and install additional compression. We've received a certificate from FERC and expect to have this project in service in mid-2007. Finally, we continue to develop several other projects around our various pipelines.

On Panhandle eastern pipeline we are working with potential shippers to make additional capacity available from a multiple natural gas producing regions to the upper Midwest. We will continue to update as further information develops. On Panhandle, we have also announced a compressor modernization project which will replace many outdated compressors across the system. This project will be conducted over the next several years and is part of our integrity and maintenance program designed to keep our system operating safely and efficiently. Now I will turn the call over to Craig Strehl.

Thank you, Rob. And good afternoon, everyone. Southern Union gas services produced an effective EBITDA of 54.4 million in the second quarter with of the hedge included. The practical effect of the gas puts is that we are selling 85% of our volumes at a minimum price of $11 per mmbtu. In fact, given the strong processing environment we are experiencing, we have been effectively able to convert much of our equity Btu's from gas to liquid and capture the higher liquids value. Our total well head volume was 598,000 mmbtu per day in the second quarter of 2006 as compared to 563,000 mmbtu per day in 2005. This represents a 6% increase year-over-year. This growth is largely attributable to numerous new well connections throughout the system over the past year.

Due to strong processing economics, we have been in full processing mode and have processed 465,000 mmbtu per day during the quarter as compared to 412,000 mmbtu per day in 2005. This represents a 13% increase in processed volumes at a time of very attractive processing economics. The resulting production impact of this is total product gallons per day in 2006 of 1.46 million, relative to 1.35 million in 2005. As it relates to pricing for the second quarter, gas prices were $5.71 per mmbtu at Waha and $5.58 at Permian. This compares to 6.30 at Waha and $6.22 at Permian for 2005.

As many of you may recall, the flexibility provided by our system and our contract structures allows us to arbitrage the basis differential between Waha and Permian and allows us to largely capture that incremental value for the Company. We're also realizing the incremental difference between the current market price of gas and our put option price of $11. From a natural gas liquids standpoint, we were able to realize $0.95 per gallon in 2006 compared to $0.74 per gallon last year. Strong processing economics and the efficiency and flexibility of our system have allowed us to translate that into a processing spread of $0.46 per gallon in 2006 up from $0.19 a gallon in 2005.

Operational results were also positively impacted from year-ago levels due to two projects completed in 2005. The first project was the completion of the 24-inch pipeline extension from the Company's Keystone plant to our Waha sales complex. The second was the completion of our connection to the Kinder Morgan owned Rancho pipeline running from Waha to KD and the consequential reactivation of the Company's Tippett processing plant. The resulting increase in operational flexibility allowed us to utilize the additional processing capacity at Tippett and maximize value throughout the system while processing margins are at historically high levels.

As a result of the hedging strategy employed by the Company in December of 2005, we are effectively selling approximately 85% of our gas at $11 per mmbtu in an actual $5.71 mmbtu market. With processing margins at $0.46 a gallon, more than twice the 2005 average. We are therefore benefiting from high commodity prices via the hedge and high processing spreads via the actual price of NGLs we are experiencing. As George mentioned, we recently entered into additional hedges to protect the earnings and cash flow of our business through 2007. As we have talked about, one of keys to our business is our operational and contract flexibility that allows us to take our equity BTU volumes as either gas or liquids, or some combination of both as market economics dictate.

When Southern Union announced their purchase of Sid Richardson in December we were in a period of high natural gas prices and correspondingly low processing spreads. That environment allowed us to hedge significant portions of our equity volumes for 2006 and '07 using natural gas as the underlying commodity. The liquids market at that point was very soft. That pricing relationship reversed in July with gas worth only around $6 and liquids worth around $12 on an energy equivalent basis. We took advantage of that situation and hedged the remainder of our 2006 volumes on NGLs. The net average hedge price for our incremental hedges in 2006 is $11.03 for the period of September through December.

For 2007, we had previously hedged 25,000 mmbtu's per day using natural gas at a gross $10 per mmbtu price. Again, taking advantage of recent market conditions we were able to hedge primarily all of our remaining equity volumes using a combination of put options on NGLs and crude at a net price of approximately $10.57. The hedge volumes of these products closely matched the physical production volumes realized by the plants the Company owns. Our ability to hedge in a variety of commodities illustrates that SUGS can truly optimize its operations in response to changing market environments and thereby reduce our overall commodity exposure and risk.

Compared to prior guidance operating results were negatively impacted for the second quarter by higher operating expense relating to the timing of certain maintenance, higher supply and service costs for material and services, and the impact of the Company's unhedged 15% volume being sold at prices approximately $5.5 below the hedged price. The Company continues to see active drilling throughout its pipeline system. As we've said in the past all volumes are not created equal. We feel that our operational flexibility coupled with our vast footprint will allow us to competitively seek out higher margin volumes to add to our system throughout this year and next. For example in the third quarter we will be connecting over 20 million cubic feet a day of new gas supplies from a variety of producers throughout our system. 15 million of which will be connected by the end of this week. I would now like the turn the call back over to George Lindemann.

Thank you, Craig. At this point we would like to open the meeting to any questions that you might have.

[OPERATOR INSTRUCTIONS] Our first question comes from the line of Sam Brothwell of Wachovia Securities.

Julie, maybe you can just take a moment and step back through how we should think about the impact of these hedges at SUGS on earnings on kind of a go forward basis, because obviously you've been able to book a gain two quarters in a row now, and this introduces another element of a moving piece, so to speak, and I was just hoping maybe you could give us a little more color on how to think about that, especially now that you're hedging based on liquids instead of natural gas at Waha.

Yes, you should expect to see us, from time to time, hedge on gas or liquids, whatever is the most advantageous commodity at that point, because of the flexibility that we've got we can actually -- and our contract structure, we can flip it either way. In the past, as Craig mentioned in his write-up, in December, when Southern Union acquired the Sid Richardson business, we bought puts in gas because at that point gas was relatively high compared to the NGL prices. As he mentioned, if you look back at sort of the price relationship on an energy equivalent basis, that completely flipped around. In July we saw the opportunity to put some additional hedges on at, frankly, a higher price level, even, doing it in the liquids. So in terms of how you think about it, I guess the answer is we do intend to continue to manage our price risk by looking at the relative pricing. We like functioning in puts because it doesn't give us a lot of downside exposure. The downside is basically the cost of the puts, and it retains the up side for when the markets get stronger.

Again, Julie this is Craig. To help people more fully understand, our system can choose whether to sell our gathered volumes as gas or convert them to liquids, not 100% to liquids, but to the extent that we have liquid production, we can hedge that as an absolute priced commodity, and, in effect, we did that with the ethane and propane and crude oil because they are actual product that we make, and right now, in a $5 gas market, you've got the equivalent of $11 for liquids. We're going to be making those liquid as long as that gas price is significantly below the liquid price so it's an actual true hedge. The crude portion closely approximates the heavy end of the barrel where we make natural gasoline and butane, and that only represents about 25% of the overall hedged volume in 2007. But we deal in absolute value of commodity prices, back in December the absolute value of gas was higher than the absolute value of liquids, so that was -- that's what was hedged. We're seeing the benefit of that each quarter and expect to in the third quarter probably. As gas prices remain low, lower than the puts. And with the high NGL prices matched closely to our NGL production, we will be making NGLs. If we don't it's only because gas prices have risen up to a point where it's more advantageous for us not to process that gas, and make the liquids. So we're a winner either way.

If I could just ask one quick follow-up, is it fair to say, based on what you've done, that having hedged out on the liquid basis you're less likely to see incremental up side to liquids prices such as you saw earlier in the year?

Well, we've -- by locking in an effective $11.03 price for the BTUs, that is what we've locked in. In effect we've converted $5 gas in to $11 gas by making the puts. It's a floor under our gas. So we do have up side if absolute gas prices rise above that $11.03 range.

But it has to be pretty extreme.

Right.

Thank you very much.

Thank you, Sam.

Jack, may I make a suggestion that if we have more detailed hedging questions, that you set up another call just on hedging and to run through the whole process of how we hedge.

Yes.

Our next question comes from the line of Craig Shere of Calyon Securities.

Hi, George does, that mean I can't ask a question on this call on hedging?

Sure, you can, go ahead. I know it's difficult to answer them all, but go ahead.

Okay. I had three questions. First on hedging, in the first quarter, before you closed on Sid Rich, or gas services, you wrote up the hedges by 39 million, as I understand it. Then in March, you had cash earnings that didn't hit GAAP accounting of 6.7 million, then you had another 21.8 in the second quarter. If you subtract those thing you come up with 10.5 million left over. What -- my first question is, should I assume in the back half of '06, and going into '07, for the legacy hedges, not the new hedges, that there will be, over that period, 10.5 million of economic earning that will not hit GAAP accounting? Am I understanding that correctly?

Julie?

Generally, yes. And it's really -- it's a very arcane area. But because we didn't get hedge accounting until March 1, we had to mark that instrument up to 88 million, which was the sum of the cash we spent to buy the puts, the 2 million gain in December, and the 37 million gain in the first two months. Then -- and if you think about it, the 49 million that we spent for them was a cash expenditure, but it was never taken against earnings. Okay? So the way to think about it is we've got 88 million invested in this instrument, we start collecting each month as the put options settle, presuming that they're still in the money, which they have been, and effectively, when we -- if prices never moved again from that point in time, when we had then recognized that 88 million we would start to book income. So the 10.5 million number that you calculated, you're conceptually right but it can change as the put options -- or as the strip going forward moves a little bit.

Sure. It looks like every quarter you're having a little hedge ineffectiveness that records a couple million up or down.

That's right. It was about 2%.

Roughly speaking, this 10.5 million, give or talk a couple, should the bulk of that come in the second half of '06, or how much would we expect to dribble over into '07?

At the rate we're going, we're picking up about 7 million a month into cash that's not going through earnings. And so if you sort of just projected at that rate, I think you would see that as we get close to the vend '06 we could get to the end of it.

Okay. Well, it sounds like you could wipe that out in the third quarter then.

It depends on where prices go, but I think that's possible.

Okay. That's the first question. Thank you. And second question, on these new hedges, I understand Craig's point, Craig, your point about we're only using the crude hedges in '07 for the heaviest part of the barrel, so there's not a lot of risk. But, we have seen other processors through the years, try to short crude oil to lock in NGL margins longer term because there's not as long a strip on NGLs. How comfortable are you with these hedges, and I guess back to Julie, is there going to be an issue about because these aren't perfect hedges, but kind of dirty hedges maybe, that we're going to have more mark to market effects?

Well, we're comfortable that the NG -- the crude barrel, at this point, within the band, is tracking closely, and keep in mind, we didn't sell short. We bought a put. So we're -- and it was relatively inexpensive, vis-a-vis the gas hedges that were put on last year. So we don't have lot at stake if I was wrong.

How much was that put?

The total puts for '07 were about $9 million premium for 50% of our volume and the crude would probably be somewhere around 25% of that. It's pretty liquid. So it's pretty easy to go out and get that. So it's not a great deal of risk associated with the insurance policy you bought, and I believe -- people get burned in the midstream business by using dirty hedges to lock in a spread, and then something goes wrong, and the spread wasn't effectively insured. This is a simple case of just buying a floor for an insurance policy.

And that 9 million covers both the NGL and crude puts?

Yes.

That's great. I'm sorry I didn't understand that before.

No problem.

Last question. As I understand it, your EPS guidance for this year includes disc ops until your two LDCs are sold in Pennsylvania and Rhode Island. That includes also the impact of the $12.3 million asset impairment and the impact of cessation on depreciation on these two LDCs, which I believe is about 33 million a year. I guess two parts. A, am I thinking about this right? And B, shouldn't that result in a net positive of an extra few million dollars because of depreciation, cessation is much greater than the asset impairment?

On A, you're correct. You are thinking about it accurately. Your question B, it shouldn't be. I mean, the way, and obviously you've picked up on this and it's a little bit sort of unique, once you reclassify an asset or an operation to asset held for sale and use disc ops accounting you do start depreciating it, and then what happens at each period end we have to recompare the carrying value of that asset to what the sales price is and to the extent that we have increased book value due to continued capital investment, for example, we have to mark it down. So it's really a function of what the depreciation would have been compared to the investment that we're continuing to make in the asset on a physical plant side, and then working capital changes can impact it. So it's not quite as cut and dried as you're saying. And at the end of the day on the day that we close the sales we will remark those assets to the contracted purchase price and probably recognize more losses against it at that time.

I got you. So roughly speaking, it's as if we continued treating these two LDCs normally.

Roughly speaking, right, that's the net impact of how it works. It's not how the accountants would describe it, but as a practical matter that's how I think about it.

Thanks for the clarifications.

You're welcome.

Our next question comes from the line of Gordon Howald of Natexis. Please proceed.

Hey, guys. Question for Rob if I could. I was wondering about the pressure that you talked about on transwestern margins. Seems California is a tight market obviously and one of your competitors earlier today cited higher revenues going into California. Can you talk a little bit about maybe the contract lengths, what you're seeing on transwestern and maybe the outlook in 2007?

Well, I think the impact that we're feeling this quarter is really the result of the So Cal contract renegotiation that we went through at the end of last year, and placing that capacity has taken us a little bit longer than we anticipated. Much of that capacity is ultimately going to end up going to southwest gas in Nevada, but that contract doesn't start until the end of the third quarter.

Of this year.

Yes.

Right. I think they covered everything else. If I need a follow-up I'll give you guys a buzz.

Thank you.

[OPERATOR INSTRUCTIONS] Our next question comes from the line of Rick Gross of Lehman Brothers. Please proceed.

Hi. I'm going to ask a question I asked last quarter. We're a little bit farther along in some of the drilling out in the Delaware basin in the shales, and we've seen a little bit of commentary out of Chesapeake and others. I'm just curious as to whether or not you're close to critical mass to lay a trunk line out there.

Rick, well, as you probably are referring to, Chesapeake acquired 125,000 acres out there. They've got a couple of commercial wells that are going into local distribution systems out there. I mean, activity continues to be active. Robust in terms of people spreading out their rigs and looking, but there hasn't -- other than EOGs, wells that they've announced that they're delivering into El Paso, everybody's been pretty tight, but we still get a lot of calls about will you guys be ready if there's -- when we consolidate and get our plans. So there's still not been one mcf of gas from the shale coming into our system, and I think it's a question of -- again, there's a lot of lease swapping going on and independent players selling out to the Chesapeake's and the EOGs of the world. They're still keeping it tight. And we don't really have anything further to report on that. Wish I did. There's still a lot of work going on out there. Just a question of sometime they're going to have to pull the curtain back and we'll see what's there.

Okay. From a standpoint of the hedges again, my assumption is that you don't have NGL, we'll call it basis risk, because of your TNF contract.

We locked in our basis risk because we physically had that contracted for.

Okay. Then on the crude piece, we'll call it the heavier end of the barrel there, do you sell that stuff locally, the butane and whatever to the local refiners? So you really don't have much of a transportation delta exposure there either?

No, we sell our NGLs at Belleview and the Gulf Coast fractionators there.

So the butane and natural gasoline goes to the Gulf as well, under the same TNF contract.

Yes.

Thank you.

Our next question comes from the line of Selman Akyol of Stifel Nicolaus.

I just have a quick question as it relates to Sea Robin. Last year you guys had a 1.5 million over recovery. Are we past all that now on a comparison basis?

Rob? I don't think anyone knows the answer to that.

Yes, we are. I'm sorry. We were doing a little digging to make sure.

Okay. Then just one other question. As it relates to your guidance of $1.70 to $1.90 does that assume a $0.21 number for this quarter?

Actually, yes, it does.

Okay. Thank you very much.

[OPERATOR INSTRUCTIONS] Ladies and gentlemen, this concludes the question and answer portion of today's conference. I will turn it back to management for any closing remarks.

Hi this is George Lindemann again. I'd like to thank you all for attending and for the very good questions, and we hope that next fourth quarter we can deliver an even better quarter, so thanks again, and see you all soon. Bye.

Thank you for your participation, ladies and gentlemen. You may now disconnect. Have a wonderful day.