OGE Energy Corp (OGE) 2003 Q3 法說會逐字稿

All sites are now on the conference line in a listen-only mode. I would like to turn the presentation over to your moderator today, Mr. James Hatfield. Go ahead please.

Thank you. Good morning, and welcome to OGE Energy Corp.'s third-quarter 2003 conference call. I'm James Hatfield, Chief Financial Officer of OGE Energy Corp. And I have with me today Steven Moore, Chairman, President, and CEO; Al Strecker, Executive Vice President and Chief Operating Officer; Pete Delaney, Executive Vice President and CEO of Enogex; Donald Rowlett, Vice President and Controller; Todd Tidwell, Manager of Financial Planning and Investor Relations; and Howard Motley, Director of Regulatory Strategies for Oklahoma Gas and Electric.

In terms of the call today, what we will do -- Steve will start with some general comments. Then I will review the third quarter and we'll talk about 2003 and 2004 outlooks. Then Howard Motley is going to give us an overview of our rate case that was filed. And then we will close with Q&A.

Before we begin, I want to remind everybody that we prepared slides to accompany our webcast so that it will be easier to follow numbers when we get to that point. And there is a printable version available on our web site at OGE.com.

Also, before we begin the presentation, I would like to direct your attention to the Safe Harbor statement contained at the end of the release. And with that caveat, I will turn the presentation over to Steven Moore. Steve?

Thanks, Jim. I would like to add my welcome to Jim's welcome to you and also thank you for your continued interest in OG&E. Today, in addition to our third-quarter financial results, we know that you are interested in our power plant acquisition efforts and our rate case filing. We will cover all of those subjects and answer any questions you would like to ask in just a few moments.

But first, this morning, we announced third-quarter net income of $99.5 million, or $1.20 per diluted share, compared with $99 million, or $1.27 per diluted share last year. For the third quarter in a row, there has been a stronger performance at Enogex, offset by somewhat-lower income at OG&E. This time, though, we have more shares outstanding, which dilutes our earnings per share. Jim will walk you through the numbers in more detail, but I want to emphasize that, from an operational standpoint, we have had an excellent quarter. We met four new records for peak electric demand, and four new records for daily system megawatt hour usage. It seemed like it was one big challenge after another, but our talented company members who operate our power plants, transition lines, distribution system, gas storage, and pipeline -- they all responded with a great performance under tough conditions. We were very pleased with the response we received in August when we sold new shares of OGE common stock in connection with our pending acquisition of the McClain Power Plant just outside of Oklahoma City, near Newcastle, Oklahoma.

As you know, I am sure, in October, our OGE stock hit a 52-week high and its near that level now. We think that the market is recognizing the successful execution of our business strategy. An important part of that strategy is in the regulatory arena. Just about a year ago, we entered into a rate case agreement that contained a $25 million rate reduction in Oklahoma electric rates, and a promise to offer our customers wind power.

The Corporation Commission also recognized our need for new generating capacity, which enabled us to guarantee additional savings of at least $75 million over a three-year period. I am pleased to report today that we are on-track to deliver everything we promised. The lower rates have been in effect since January. Wind power is now available to our Oklahoma customers, and they have been voluntarily signing up for it since September.

In August, we announced we will add 400 megawatts of generating capacity by acquiring a 77 percent interest in the McClain power plant. Two weeks ago, we filed with the Oklahoma Corporation Commission, what we are calling our "customers savings and reliability plan." As a part of that plan, we are asking for a rate increase of $91 million. That will help fund our acquisition of the power plant and enable us to invest in the electric system reliability and address rising business costs for things like health care and insurance. If our plan is approved, we will deliver the savings we guaranteed in the agreement last year.

Schools and small businesses stand to benefit the most from our plan. But again, it all hinges on the new power plant that makes the savings possible. The new plant has high-technology efficient operations, and enable us to allow a number of purchased power contracts to expire. Including, the new power plant in our regulated rate base, also represents an opportunity for earnings growth for our shareholders. We really have a unique opportunity here to do a lot of good for our customers and our company, as well.

Our goal is to have a commission order in time for our new rate plan to be effective in May 2004. We had received clearance under Hart-Scott-Rodino to complete the power plant acquisition, and the United States Bankruptcy Court in New York has approved the sale of the plants by NRG to us. We expect soon approval from the FERC, which will enable us to take ownership of the plant by the end of the year. As you have heard me emphasize before, and I will repeat again today, we do have a sound, conservative business strategy.

During this year, 2003, we have executed our plan. We have improved financial performance at Enogex; we have begun a new wind power program; we are acquiring the new power plant; and we have prepared an excellent case for our state regulators.

Now, for our strategy to take the next positive step, we need that regulatory approval. We have a formula for customer savings and earnings growth. We have an award-winning record of customer service and specific plans to improve the reliability of our system. We also have the support of an investment community that recognizes long-term value, and I thank you for that.

Now, for more details of the quarter, I will turn it back over to Jim. Jim?

Thank you, Steve. I would now like to cover the earnings of OG Energy Corp., and I will start with the discussion of the third quarter, discussing contributions of the business units in the quarter; reaffirm the 2003 outlook; provide 2004 guidance; and finally, Howard Motley will discuss the rate filing.

Beginning with the third quarter, we reported net income of 99.5 million, or $1.20 per diluted share, as compared to net income of 99 million, or $1.27 per diluted share in the third quarter of 2002. The contribution by business unit, on a comparative basis, is as follows -- OG&E, $1.15 versus $1.26 in 2002; Enogex, 10 cents versus 5 cents; holding company, a loss of 5 cents versus a loss of 4 cents; consolidated, $1.20 versus $1.27.

For OG&E, net income of 95.1 million, or $1.15 per share, as compared to net income of 98.4 million, or $1.26 per share, in the third quarter of 2002. Gross margins decreased to 274.2 million, from 281.6 million. The major drivers for the decreasing gross margins were weather -- (indiscernible) days were 3 percent above last year, 2 percent above normal; and growth, which were more than offset by lower rates, the results of the rate reduction, and the impact of the energy credit rider. You see the relative contributions on the chart, weather, and growth, 6.2 million, offset by the ECR, 5.6 and lower rates of 7.4.

I would also like to mention that we had previously discussed the ECR, and we changed the accounting for it in last year's fourth quarter. So this will be the last quarter we need to mention that rider.

O&M expenses increases 2.6 million, or just under 4 percent, to 71.5 million. The largest increase in O&M expenses came from pension and benefits, which were partially offset by lower levels of bad debt and outside service cost.

Other expenses were lower by about 900,000, primarily from lower depreciation rates. There was also an income tax true-up of 1.5 million, which provided a positive benefit. And average shares outstanding increased to 82.4 million from 78.1 million in last year's quarter, resulting in a dilution of 6 cents per share.

For Enogex, net income more than double to 8.4 million, or 10 cents per share, in the third quarter of 2003 from 4.1 million, or 5 cents per share, in the third quarter of 2002. Net income from continuing operations were 10.2 million in the third quarter of 2003 -- up from 2 million in last year's quarter.

At Enogex, gross margins increased 18 percent to 64.2 million from 54.2 million in 2002's third quarter. You see the relative contributions of each business -- transportation and storage -- gross margins of 38.9, as compared to 33.2. Gathering and processing, 23.5 million, as compared to 19.5. And marketing and trading, 1.8 million, as compared to 1.5 million. So, in summary, gross margins were up at all the Enogex businesses.

Looking specifically at the transportation storage business, gross margins were 38.9 million, up 5.7 million from last year's quarter. The major factors driving increased gross margins were firm transportation revenues, which were higher, primarily due to the settlement of a contract dispute -- partially offset by interruptible revenues, which fell 2.2 million, the result of internal allocations to the gathering business. These are gathering revenues, which previously classified as interruptible revenues. And the allocation better reflects the profitability of each business. Additionally, storage demand fees were higher, primarily due to the acquisition of the Stewart (ph) storage facility.

For gathering and processing, gross margins were 23.5 million, an increase of 4 million over last year's quarter. Processing gross margins were up 700,000, due to a better commodity price environment. Gathering gross margins were up 3.3 million, due primarily to the allocation of revenues from the transportation business that we previously mentioned, as well increased fees in gas purchase margins. Additionally, marketing and trading business was up slightly.

On the expense side, we saw lower expenses, generally, across the business. Operating expenses decreased 1.4 million. Lower O&M and depreciation expenses were partially offset by higher property taxes. Interest expense fell 2.6 million, due to the reduction of long-term debt associated with our deleveraging efforts. And income from discontinued operations negatively impacted reported earnings by 3.9 million, on a comparative basis, from the third quarter of 2002. And this 1.8 million loss in this year's third quarter was formerly a reversal of Section 29 tax credits that were taken in prior period. We, as you know, owned the A&P (ph) business in 2002, and in a minute I will talk about a tax change that we made, which generally disallowed our ability to take those tax credits in 2002, so that is a prior period reversal.

On the cash flow statement, you see a large per-tax benefit this quarter and OG&E Energy was able to take advantage of an election under IRS procedures -- changed our accounting methodology for self-constructed assets. The net effect of this election was that the company took a one-time adjustment to income taxes, resulting in an approximately 75 million positive cash flow benefit in the third quarter.

In terms of 2003 outlook, as Steve mentioned, we continue to support our guidance of $1.40 to $1.50 per share, although we expect to be in the upper end of the range. And although we've earned $1.63 year-to-date, we see a number of factors that will influence the fourth quarter. After utility, we see an additional $7 million of rate reduction as part of our $25 million rate reduction. We also forecast higher O&M expenses, primarily due to power plant maintenance. Last year, the utility had O&M expense of 73.8 million in the fourth quarter, and we would expect to see this year's fourth quarter O&M to be in the 78 to $80 million range.

We have increased our guidance at Enogex to 20 to 22 million on a reported basis. However, Enogex will take a pre-tax impairment charge of between 7.5 million and $10 million for (indiscernible) assets in the fourth quarter. Just pointing out that this impairment charge included in our 20 to $22 million guidance.

The holding company will lose 4 to 5 cents per share in the fourth quarter. In addition, shares outstanding in the fourth quarter will be approximately 87 million versus 82 million for the full year.

In terms of 2004, we will project net income of between $1.40 and $1.50. The range does not incorporate any rate release. As you are aware, and Howard is going to talk about in a minute, we fought for a $91 million rate increase on October 31st. For 2004, OG&E will expect higher gross margins, due to growth and normal weather; however, higher gross margins will be offset by higher levels of O&M, interest, and depreciation expenses, primarily due to the acquisition of the McClain power plant. Therefore, we would expect to see OG&E earn between 109 and 113 million.

Enogex's earnings are expected to be 25 to 29 million, based on higher gross margins and lower interest expense. And we would expect the holding company to lose approximately $12 million, and improvements due to lower levels of commercial paper outstanding. And with that, I would like to turn it over to Howard Motley, who is going to provide an overview of our rate filings. Howard?

Thanks, Jim. The company filed the rate case on October 31st of this year. It is kind of a two-part plan -- it's a customer savings and reliability plan. We have requested a $90.8 million increase in rates, and we have proposed several reliability programs that we believe are necessary for the company for service to our customers. The rate increase calculation is based on a 12 percent return on equity, and a 56.573 common equity portion of the capitalization ratio.

We have included the new plant that we talk about earlier. And, there is approximately 175 million in our investment on a return-on for the new generation facility, the McClain plant, and about 9 million of that is deregulatory asset that was authorized by the commission in the settlement agreement. The company has also requested a level of O&M expense of 316 million, of which of that -- about 9 million of that is for the proposed reliability programs.

The rate increase category is kind of the big picture of the categories that add to the 90 million -- 37.5 of it is due to the new generation facility. 22.2 million is escalating operating costs, such as medical, pensions, bad debts, payroll. And 8.2 million is related to the proposed reliability programs. And then we have 4 million of it as nondiscretionary assessment -- it is an increased assessment to the Southwest power pool that we have to begin paying in January of '04. And then we have some capital projects in generation that require about a $2.4 million annual revenue requirement. And then, there is about 16.5 million of the 90 million that are normal, historical adjustments for weather, normalization of revenues, rate case expense, you know, other items like that.

The reliability segment of the plan -- we are proposing three programs. One is a three-year tree-trimming cycle. We want to increase the tree-trimming to get on a three-year cycle to be able to help reduce the impact of future storms on the system. We also have a vegetation management capital program, which would not increase the cost of the 90 million, but it would be a capital cost that we would recover in the future. And, what that program would be -- we'd go in and cut trees down instead of trimming the trees. And again, to spray in the future, which, in the long-term, would reduce some of our tree-trimming expense. We believe that those two programs are best practices approach for the company in managing our electric system. We also have requested the commission to approve 3 million a year for an outage management inventory to go out and perform a more accurate inventory of our facilities, which would help speed up restoration of service during storms.

The second part of our reliability segment is investment in generation capital projects to improve efficiency and reliability of our coal plants. It would also bring in some fuel savings to the consumers. That is about $19 million a year. And then, we have also requested a fuel (indiscernible) inventory increase of about 6 million a year to be used for fiscal hedged against rising natural gas prices.

The last line on the rate case is the timing on it. We filed a notice in September required by Commission rules. We filed the rate case on October 31st, and the Commission has 180 days, by statute, to complete the hearing. So, the hearing on this case has to be completed by April 27th of 2004. If the Commission issues an order, we will be able to implement our rates. If they haven't issued an order by May, the company has the right, under the statute, to implement the rates subject to refund in the first billing cycle in May. Back to you, Jim.

Thank you, Howard. That concludes our prepared remarks today, and we would open it now for Q&A.

(OPERATOR INSTRUCTIONS). David Frank (ph), Zimmer Lucas (ph) Partners.

Jim, maybe you could help me out here. What would you expect the electric utility to report this year?

Well, based on the guidance of 112 to 118 and based on the (indiscernible) of about 1.1 billion in equity, it would be right around 10 percent or so at the utility.

10 percent? And then you forecasted for next year -- I think you said that, due to rising costs, the contribution from the utility will likely be down. Would you expect to report an ROE, absent any rate release somewhere in that 10 percent range again? Or south of 10 percent?

It would be in that general vicinity. As we have said, next year 109 to 113 -- earnings would be essentially the same with the same equity base. So -- (multiple speakers) -- it would be around 10.

Then I just want to ask about the acquisition of the McClain plant. That is excluded from your earnings guidance for next year, as well?

The expenses are in the plan -- depreciation, O&M, ad valorem, all interest costs. What is not included is any revenue from the rate increase.

So, there's no return component factored in?

Correct.

What is the size of that plant again -- it's 164 million?

Well, is 160 million for 400 megawatts.

160 million. And you are requesting the same capital structure and return on that plant as we saw on the slide? A 56.5 and 12 percent?

Correct.

Okay. Great. Congratulations on Enogex; that is quite a turnaround.

Thank you.

Sharina Chowdhury (ph), Merrill Lynch.

Jim, I find in one of your slides you had the operating earnings from Enogex was different than the reported earnings. I am wondering if you can give us what the continuing operations earnings are, year-to-date? And, if that is included in the guidance that you gave for Enogex or not?

The continuing operations at Enogex, year-to-date, is $28 million, 9 months ended. And then we have continued operations -- is about a negative 5, year-to-date. And we also have the accumulative change in accounting principle of 5.9. So, reported net income at Enogex, year-to-date, is 21.6.

And is the reported net income guidance that you gave in the 2003 outlook?

(multiple speakers)

The 20 to 22 million?

Yes.

Okay. Thanks.

Andy Levy (ph), Bear Wagoner (ph).

Just two quick questions -- 100-basis-point difference in ROE, if you can just give us that. And what is your common equity level now that you're earning on?

Our 100-basis-points difference in ROE is about 17.1 million, pre-tax, and about 10.6 net income. And the common equity, right now, is about a billion dollars, slightly under a billion dollars, about 950 million.

What percent is that?

At the utility?

Yes, relative to the 56 percent number you threw out -- is it the same amount, common equity level?

Yes. Yes.

Thank you.

Jeff Gilderslee (ph), Millennium Partners.

I apologize if this was asked. But, just going back to the impairment at Enogex. You mentioned that was 7.5 to 10 million, pre-tax. Was that -- when was that taken? Are you expecting to take that in the fourth quarter?

Yeah, that has not been taken. We expect to take that in the fourth quarter; that is a subsequent event from the closing of our third-quarter books. And, it will be booked in the fourth quarter.

And, do you have -- you've included that in the guidance for the year?

Correct.

Okay. So, absent that impairment next year, you're looking for an increase at Enogex. Is there a difference if we added that impairment back in? What other drivers do you see, potentially, moving Enogex up?

Well, you have two main factors for 2004. We're going to have slightly higher gross margins at Enogex. The expense side will be fairly flat, all O&M, depreciation, ad-valorem taken together. And then the other big driver is reduced interest expense, as we continue to pay down debt. That is, essentially, the change.

Okay. I guess what I'm getting at is if the 20 to 22 million has a pre-tax impairment of 7.5 to 10 million. You know, if we tax effect that, that brings up the earnings tower 4 or 5 million, maybe. And then, so it looks fairly flat into the next year, but you are also citing better gross margins and some improving conditions. So, I'm wondering if there is any opportunity to improve on what looks more like a flat year-over-year continuing operations?

When you look at the 20 to 22, you have to look at all of the things that go into that number this year. For example, we had the gain on the sale of assets earlier in the year, which we took in the first quarter. It was about 4.7 million. We have also had discontinued operations -- some prior period adjustments that came over into 2003 from 2002, offset by impairment charges. So, when we're looking at the 20 to 22, I think you have to take out what we consider more one-time items throughout the course of the year to get back to that number.

We've also had on the gross margin basis in 2003 -- we had a fuel gain in transportation business, which is a recovery of fuel from prior periods under collections. And that had about a $7 million margin impact on transportation. So, when you look at margins, you will have to take out the fuel and the prior period's estimate to get at a more normal level, which is what we are coming out from the 20 to 22.

Okay. Was that 4.7 7 million pre-tax numbers?

4.6 was after-tax. The 7.5 to 10 is a pre-tax number.

I think you just cited 7 million, as far as the transportation -- (multiple speakers)

I'm sorry, that is a pre-tax number; that is a margin contribution.

Okay. And then the gain of 4.6 was after-tax?

Correct.

Okay. With that aside, you're looking at some conditions there?

Margins will be up 4 percent or so on a normalized basis, and then interest expense will be down. And that is essentially the year-over-year reconciliation.

Okay. Great. And then, on the rate case -- could you just explain again the miscellaneous adjustments? I did not catch all of that.

The miscellaneous adjustments?

16.5 million --

The 16.5 million? Probably, we've made 38 adjustments to the operating income, and some of them are as small as $100,000, and some of them are a million (indiscernible). It's just an accumulative effect. And it is the historical adjustments that are usually accepted by the commission. So, what we are trying to point out in this chart was the major areas that I believe that the Commission will be looking at in determining the rate increase for the company.

Right -- I think you named a few of the miscellaneous adjustments, or a few of the major miscellaneous adjustments. Can you say that once more, please?

Weather normalization of revenues, you know, would be one of them. Rate case expense, year-end customers, interest on customer deposits -- those type of adjustments. The 38 adjustments were found in our application package in schedule H2.

Great. Thank you.

Douglas Fischer, A.G. Edwards.

Most of my questions have been asked and answered. But, on the transportation and storage -- firm transportation revenue, the change for the quarter, you talked about a settlement of a contract dispute. Remind me, Jim, was that in the current quarter or the year-ago? Quarter? The recent quarter or the year-ago quarter?

The dispute came in 2002.

Okay.

And we reached settlement in this year's quarter. So that is why you have a positive change.

So, which one was -- this year's was boosted by sort of an outer period adjustment? Is that what you are saying?

We had a dispute last year, in 2002, which we reserved for. We settled the dispute this year.

And how much had you reserved for? And what was the reverse -- did you reverse part of the reserve?

We reserved a little over 2 million last year on a net income basis. And on a net income basis, this year, we picked up about $2 million of net income, on settlement of those prior periods.

So, it was essentially reversed?

Essentially. A slight positive to the company, but it was a reversal prior period.

Thanks. That is really it at this time.

(OPERATOR INSTRUCTIONS). David Frank, Zimmer Lucas Partners.

Jim, I just wanted to clarify something that you had said before. Maybe I am misunderstanding you. I think you said that, for next year, you're assuming the expenses associated with the acquisition of the McClain plant, but you had no revenue benefit?

Correct. We're assuming no rate release.

No rate release, but -- (multiple speakers)

But, what is in our numbers are O&M and interest charges, depreciation, and those things associated with the plant -- assuming that we buy and it goes in service.

Okay. So what is -- are there savings from the fall-off of the QF (ph) or PPA (ph), which enable you to absorb those costs, then? Or --?

Well, if you look of the utility being slightly down, you know, we're going to have normalized weather, which is about 4 million in growth, or 2 percent, which is about 14. So we are generating 18 million or so on the revenue lines if normal business. And then we are absorbing someplace over $20 million in expenses associated with -- not only the power plants -- they're just normal operating expenses of the utility year-over-year, like labor increases. It also assumes that we would capitalize a deregulatory asset for part of the year. What we have assumed essentially is that we close on the plant, and we would get a -- you start booking expenses of the plant in '03 -- excuse me, in '04, in May -- just as if --. But we have not assumed any revenue from the rate increase. And I think the intent was to -- you know, Howard outlined the case and the specifics of the case so people know what is in the case. But we have not assumed that in our guidance.

Okay. I'm just trying to figure out if that is a little conservative, given the fact that you should (multiple speakers) at least get recovery of operating -- forget the return on the investment for a moment --.

We expect to be successful on our regulatory filing. But, we have not assumed any revenue associated with that in our outlook.

So, is there a potential for revenue increase, then, to cover the operating expenses of the plant, plus an opportunity to earn a return on the plant -- the investment itself?

Well, we have -- you heard Howard talk about the revenue requirement of the plant, which is one component. We also filed for over $20 million of O&M recovery, which are increased operating costs. So, you know, the (indiscernible) could be more than just the power plant; it's going to be to make -- recover all of our operating expenses and allow us to earn our return.

Right. And just one last question on pension expense. Do you have any forecast of what increase pension expense might be next year, relative to this year?

We see pension expenses being up about 4 percent.

Can you give that in terms of millions of dollars?

We were at 39.1 million in '03.

(inaudible) Okay. Thank you.

David, just to clarify, what we are doing on our guidance is -- we have assumed all of our operating costs for '04. And we are just asking -- you know, and give you the proponents of the rate case -- you guys, to go to your question "are you we conservative?" You guys can go to various components and handicap what you think the appropriate rate release will be, as opposed to the company trying to provide that for you.

Is there an opportunity, do you think, to reach a settlement like you have in the past with the Commission here? Or do you expect this to be a fully-adjudicated case?

This is Howard Motley. I believe that there will be a very good opportunity. According to the rules, the Commission were required to sit down and try -- attempt to settle the case before we go to hearing. And with the case that we have provided, with the offsets of some of the costs going down, I think there's a very good chance for a settlement in this case.

Okay. All right. Thank you very much.

Douglas Fischer, A.G. Edwards.

To just sort of follow up on what David was asking about -- you have a capacity contract that drops off -- correct?

Correct.

Remind me of the amount of that and the timing.

We have the Smith cogeneration contract, which expires August 31 of 2004. And the capacity component of that in '04 is $13 million.

Okay. That is in base rates, correct?

That is correct.

So, that is a -- are you assuming that that 13 million is not in base rate in this '04 guidance? Or are you assuming that you're still collecting that $13 million?

We are assuming that once that contract expires, we no longer collect it. So, we are not collecting the revenue, and basically -- nor are we paying a capacity payment.

So, it is a wash from our perspective in the outlook.

I am a little puzzled. Maybe I am dense, but I did not catch that Jim? Because I would think that if it is in base rates, it would take a rate decrease to take it out.

What we have is, we have a credit rider. In other words, when the Smith contract goes away, there's an automatic credit rider that will go against the base rates to zero out the 13 million.

So, when you say it is in base rates, it's a little bit -- is not -- it's an adjustable portion of base rates?

Well, there was a rider put in, in this last rate case, Doug, that basically insured that when that contract goes away, that we stop collecting that from customers. And it basically insured that we don't terminate the contract and have to go to a rate proceeding to stop that collection. So it was created, in this last case, as an automatic pass-back (ph) mechanism, even though it's in base rates.

And that rider applies to all co-generation contracts.

Okay. And when you talked about your guidance for this year for the utility being at 10 percent ROE, are you using the equity balance at the end of the year after the equity issuance?

Yes.

So, your average return on equity for the year is going to be somewhat higher than that 10 percent?

Yes, average would be higher. But, year-end equity would be roughly around 10 percent or so.

And once again, that year-end equity is what, Jim, roughly?

It is going to be roughly 1.1 billion or so, in that, vicinity.

And that is the utility?

Yes.

Okay. Thank you so much.

You are welcome. Thanks.

At this time, we have no further questions.

I would like to just close us out by saying we appreciate your interest in the company. Thanks for being with us. Have a good day. We are adjourned.

This concludes today's presentation. You may disconnect your lines at this time.