Black Hills Corporation (BKH) Q1 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation 2013 First Quarter Earnings Conference Call. My name is Keith, and I'll be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. And with that, I would now like to turn the presentation over to Mr. Jerome Nichols, Director of Investor Relations of Black Hills Corporation. Please proceed, sir.

Thank you, Keith. Good morning, everyone, and welcome to the Black Hills Corporation 2013 First Quarter Earnings Call. With me today are David Emery, Chairman, President and Chief Executive Officer; and Tony Cleberg, Executive Vice President and Chief Financial Officer. Before I turn over the call, I need to remind you that during the course of this call, some of the comments we make may contain forward-looking statements as defined by the Securities and Exchange Commission, and there are a number of uncertainties inherent in such comments. Although we believe that our expectations and beliefs are based on reasonable assumptions, actual results may differ materially. We direct you to our earnings release, Slide 2 of the Investor Presentation on our website and our most recent Form 10-K and Form 10-Q filed with the Securities and Exchange Commission, for a list of some of the factors that could cause future results to differ materially from our expectations. I will now turn the call over to David Emery.

Thank you, Jerome. Good morning, everyone. For those of you following along on the webcast presentation, I'll start on Slide 3. The agenda will be similar to previous quarters. I'll go through the quarter highlights. Tony Cleberg, our Chief Financial Officer, will cover the financial update for the quarter. And then I'll give a strategic overview, kind of a forward-looking slant after that and then we'll open it up for question and answers. Starting on Slide 5, highlights of the quarter. Business environment-wise, we had a slightly colder than normal winter, which was a big change compared to the very warm winter the year before, and you'll see that in our results. And also, a significant rebound in gas prices. Henry Hub prices more than $1 higher than they were 1 year ago at the same time. Highlights for the utilities, construction commenced in early April, on our Cheyenne Prairie Generating Station, the $237 million, 132-megawatt plant we're currently building in Cheyenne, Wyoming for both Black Hills Power and Cheyenne Light. And our Colorado electric utility, we filed an Electric Resource Plan earlier in the week on April 30, with the Colorado PUC. In that plan, we identified a 40-megawatt, simple cycle gas turbine as the replacement for our retiring 42-megawatt W.N. Clark coal plant, under the Clean Air-Clean Jobs Act in Colorado. And we also recommended retirement of 2 older gas-fired plants in Pueblo. Those 2 plants have a total capacity of 29 megawatts, and they were placed in service in the 1940s. In connection with the resource plan, we also filed 2 certificates of public convenience and necessity, 1 seeking approval for the new turbine and 1 for the retirement of the 2 gas-fired units in Pueblo. Also related to Colorado Electric, on April 23, we issued a request for proposals seeking bids for up to 30 megawatts of wind energy. We're still evaluating whether our nonregulated power generation sub will submit a bid into that RFP. Moving on to Slide 6, relative to the Black Hills Power rate case we filed in December of last year, we plan to implement interim rates subject to refund in the middle of June. We received a schedule from the commission and the public hearing related to that rate case as currently scheduled for October 8 through 11. Also last December, we filed a request with the South Dakota PUC seeking approval for the construction financing rider for the Cheyenne Prairie Generating Station. The commission approved us implementing that on an interim rate basis, that was done effective April 1, subject to refund. The hearing on the financing rider has been scheduled for September 16 through 20, at which time, we would expect, after that, a final decision related to that rider. Also during the quarter, our Gas Utility segment purchased 2 small municipal gas systems, 1 in Iowa, 1 in Kansas, adding about 500 retail and a couple large volume industrial customers. This just continues our trend of purchasing small municipal gas systems, really to help offset the low growth in a couple of our service territories on the natural gas side. And in the last few years, we've completed 6 or 7, I think, of these transactions. Slide 7. Highlights for our Power Generation for the quarter. We're currently in the process of reviewing options for our Gillette CT II. It's a 40-megawatt combustion turbine located in our Gillette Energy Complex. That plant is currently under contract to sell basically all of its output to Cheyenne Light on a contract we signed clear back in 2001. It expires in August of 2014. And so we're exploring options for that turbine after that time. Those include potentially recontracting with Cheyenne Light or another party or even likely selling all or a part of that unit to a third party. Moving on to Oil and Gas, we recently commenced here, just in the last couple of weeks, drilling the first of 2 wells in the Mancos Shale formation in the Piceance Basin. These wells are being drilled as part of a transaction that we did with a third-party where we will earn up to an additional 20,000 net acres of Mancos Shale leasehold in the basin from a third-party in exchange for drilling and completing the 2 wells. That agreement, not unlike a lot of agreements in the Oil and Gas business, has some pretty strict confidentiality provisions. So that agreement with that third-party not only precludes us from identifying the party, it also requires confidentiality of all the contract terms and in addition, the drilling and production information will be kept confidential for at least 6 months after the wells are completed. It may be longer depending on the concurrence of the other partners involved in those wells at that time. Now this is the change in plans. We elected to drill the 2 wells on this third-party acreage rather than our own acreage for a couple of primary reasons. First, we're still waiting on BLM approval of our drilling permits on our own acreage. That process has been ongoing for more than 18 months. We did, just yesterday, receive approval of our environmental assessment from the BLM, but we still don't have the first couple of drilling permits yet. So doing the third-party transaction allows us to get started on our drilling sooner than we would if we had to wait for our own permits. And more importantly, by drilling and completing those 2 wells and bearing the cost of that, we'll earn up to 20,000 additional net acres in the Mancos, which increases our holdings in the Mancos almost 27% from our current 74,000 acre level. On the corporate side, our Board declared a quarterly dividend of $0.38 a share, that's an annual rate, assuming we continue that rate for the following quarters, then $1.52 per share. Again, this year, marks our 43rd consecutive annual dividend increase for shareholders, one of the longest streaks in the industry. Moving on to Slide 8. During the first quarter, we earned $0.87 per share from continuing operations as adjusted compared to $0.65 last year, an improvement of 34%. The positive impacts of more normal weather, new utility rates, higher demand in our electric utility and significant decrease in interest expense was partially offset by lower oil volumes due to our asset sale in Williston Basin and lower natural gas prices. On Slide 9, it just illustrates the changes in income from continuing ops as adjusted from the first quarter of last year to the first quarter of this year. As I mentioned earlier, the improvement was primarily driven by our Utilities and our Corporate segment. Now I'll turn it over to Tony Cleberg, our Chief Financial Officer, to provide the financial update. Tony?

Thank you, Dave. As Dave mentioned, we had a really strong quarter. We're very pleased. Looking at Slide 11, we reconciled our earnings from continuing operations on a GAAP basis to EPS as adjusted, which is a non-GAAP measure. We do this each quarter and feel by isolating the Special Items EPS as adjusted, better communicates our most relevant performance. During the quarter, we only had 1 special item, which was a reduction of $0.11 for a noncash mark-to-market on $250 million worth of interest rate swaps. The gain reflected an increase in the long-term interest rate during the quarter. So considering the special item, the first quarter earnings EPS $0.87 compared to the $0.65, which is the 34% increase. Slide 11 displays our first quarter revenue and operating income. Later, I'll explain the major differences between the years. But here, the main point is we are predominantly a regulated business, generating 89% of our operating income from the Electric and Gas Utilities in the first quarter. Our operating income was strong, increasing by $9.8 million or 14% compared to 2012. More normal weather in 2013 accounted for about $6.7 million of that $9.8 million improvement in operating income. Slide 13 displays our first quarter income statement. On later slides, I'll discuss the segment revenue and operating income in more detail. But here, I want to mention several noteworthy items that impacted our first quarter performance compared to the prior year. First item was interest expense, declined by $4.3 million, and that was driven by reduced debt of $220 million. As you may recall, we paid off $225 million of 6.5% notes in the fourth quarter of 2012, with the proceeds from the Williston Basin asset sale. The second item was the reduced tax rate. The rate in the first quarter was 33% compared to 36% in the prior year. The lower tax rate in the first quarter primarily reflects increased R&D credits, including the full year estimated benefit of 2012 due to the retroactive reinstatement provided by the American Taxpayer Relief Act of 2012. Also the first quarter 2012 included an unfavorable state tax true up, which bumped it up about 100 basis points. Third item relates to performance incentive costs that are included in operating expenses. An important part of our performance plans is that they are directly aligned with our stakeholders. Those plans are based on stock performance, and with a 21% increase in stock price during the first quarter, we incurred an additional compensation expense of about $2 million. Those expenses gets spread across pretty much the entire company. The last noteworthy item was our increased EBITDA. During the quarter, we achieved $115 million of EBITDA or an increase of 4% over 2012. This is particularly noteworthy since the first quarter of 2012 included the performance of the Williston Basin Oil and Gas wells, which we sold in third quarter of 2012. Moving to Slide 14, here, we displayed the Electric Utilities segment revenue and operating income on the top. The Electric Utilities revenue increased in the first quarter by $3.4 million, and this reflects about $7 million of new rates and higher demand, offset by lower off-system sales. Our first quarter operating income as adjusted improved $5.1 million or 17% year-over-year. About 75% of the improvement was driven by increased retail and wholesale demand. The remaining 25% increase was a combination of new rates and riders. Expenses were about flat year-over-year. Moving down on Slide 14, the Gas Utilities operating income improved $4.9 million or by 16% in the first quarter compared to 2012. The distribution decatherms sold increased about 24% year-over-year. As you will recall, last year was one of the warmest winters on record, and this winter was slightly colder than normal. O&M expenses increased slightly due to the expense allocation. All in all, we saw a strong performance from our utilities, both gas and electric. The next segment, Power Generation, was relatively close to last year's performance. We are pleased with the performance in availability and earnings that we continue to see from our Colorado IPP. On the bottom of that slide, Coal Mining segment, we saw operating income improve $800,000 from 2012. The tons sold decreased by 5%, and the mining costs decreased by 10%, driving the average price lower by about 5%. As you will recall, just over 50% of our coal production is priced on a cost-plus basis. We are encouraged by the continued improvements that we see in our coal mine. Moving to Oil and Gas on Slide 16, the segment performed as expected. Two major items in 2012 impact the year-over-year comparison. First, we delayed our natural gas drilling program last year because of low prices. So our gas production declined year-over-year by 27%. The second item is we sold our largest oil-producing properties in the Williston Basin last fall. So our oil production declined by about 33% year-over-year. Overall, first quarter production decreased 28% from 2012. From a cost perspective, our O&M costs were slightly lower. Depletion decreased by $3.9 million from 2012, driven by the impact of selling the Williston Basin assets and lowering our cost pool capitalized cost. The actual depletion rate during the first quarter was $1.78 per Mcf -- MMcf, which was slightly higher than we originally estimated in our earnings guidance assumptions. From the non-operated oil wells in the Bakken, as they came online near the yearend last year, this increased our cost pool, but this also increases our profitability because these are oil wells. Sequentially, from the fourth quarter of 2012 to the first quarter of 2013, total production increased by 16%. This was driven by a 30% increase in oil production and a 10% increase in natural gas production. Prices received decreased 4% for oil and decreased 21% for natural gas. Moving to Slide 17, our capital structure. Here, we show our current capitalization. At quarter-end, our net debt-to-capitalization ratio was 50.3%, an improvement from yearend. With the cash flow from operations, our debt capacity, we have ample funding available for our capital expenditures and dividends through the next year. Moving to Slide 18, earnings guidance. In the press release, we reaffirmed our 2013 earnings guidance in the range of $2.20 to $2.40. This is EPS as adjusted and excludes special items. On Slide 18, we list the primary assumptions we made regarding the 2013 earnings guidance. We've not changed our published assumptions because we believe, in total, the assumptions are reasonably accurate for the guidance range that we have provided. To conclude, we're very pleased with our first quarter performance. And the more normal weather helped, and we continue to manage our operations effectively. And with those comments, I'll turn it back to you, Dave.

All right. Thank you, Tony. Moving on to Slide 20, we have 5 major strategic objectives, all of which are focused primarily on being an industry leader in essentially all that we do. These are consistent with what we've shown you the last couple of quarters. We really want to strive to be an industry leader in operational performance, earnings growth, tremendous upside opportunities through our Oil and Gas assets. And of course, our track record of 43 consecutive years of annual dividend increases. We also have a goal of increasing our credit rating. On Slide 21, related to operating performance, that slide exhibits exceptional performance relative to our peers in several metrics. Safety, reliability and in several efficiency measures in our Gas Utilities. On Slide 22, that illustrates our superior power plant availability and starting reliability. Also demonstrates that we have an extremely modern generation fleet. And then we have an exceptional safety record on power plant construction, well, well below the industry average. Slide 23 gives an overview of our generation by fuel price and then further demonstrates the recent modernization of our generation fleet. Slide 24. We expect continued strong earnings growth as we've demonstrated over the last several years, driven primarily by capital spending, both to meet customer needs in our utilities and to grow our nonregulated energy businesses. And for the next several years, capital spending is projected to continue to be far in excess of depreciation. Slide 25 just provides more detail regarding historical and projected capital spending, really broken out by business segment. And for our Electric Utilities, breaks out the generation and transmission as well. Slide 26. When we talk about future earnings growth, helping drive that growth is our Cheyenne Prairie Generating Station, our new 132-megawatt plant that we just started construction on. We expect that plant to be in service by the fourth quarter of 2014. Slide 27. The utility regulatory update. I've really covered all of these in the initial quarterly highlights, except to point out one thing, and that is related to the Cheyenne Prairie Generating Station. We will need to file rate cases for both Black Hills Power in Wyoming and South Dakota, and Cheyenne Light in Wyoming in late 2013 or early 2014, in order to have those rates in effect on the date of commercial operation of the plants. Again, that's expected in the first -- in the fourth quarter of 2014. Slide 28. As we demonstrated last fall with our 2012 Williston Basin asset sale, our Oil and Gas properties represent a tremendous upside opportunity for our shareholders, and we're very focused on demonstrating the value of our existing Oil and Gas properties. We plan to participate in limited exploration opportunities, focusing primarily on oil plays with impactful reserve potential. And as I mentioned earlier, in 2013, we plan to continue to advance our Mancos Shale gas opportunity, particularly in the Piceance Basin, where we started drilling here in the last couple of weeks. Slide 29 just illustrates the resource potential of our existing oil and gas leases in the Piceance Basin relative to the Mancos formation. We estimate that resource potential to be in excess of 2.2 trillion cubic feet of net resource. Slide 30. As I mentioned earlier, we're very proud of our track record of increasing dividends for shareholders, now at 43 years to our benefit here. We also had a larger increase this year than in the prior several years. I think, signaling our confidence in our ability to continue to grow income and cash flows to support a slightly larger increase in our dividend. On Slide 31, we remain focused on improving our credit rating. As we've discussed in the last couple of quarters, we were able to receive an improvement in ratings outlook from both Moody's and Standard & Poor's last fall, and look to hopefully follow that up with a rating increase at some point in the future. Finally, Slide 32 is our 2013 scorecard. This is something that we continue to do and we've done it for several years. Basically holding ourselves accountable to you, our shareholders. This scorecard sets out our goals for 2013, and indicates which ones of those we've accomplished to date so far. That concludes my remarks. I'd be happy to open it up for questions.

[Operator Instructions] First question is from the line of Kevin Cole with Crédit Suisse. Kevin Cole - Crédit Suisse AG, Research Division: I guess, Tony, I'll start with a question about the balance sheet. So I see that you have some monster 9% debt due next year.

Yes. Kevin Cole - Crédit Suisse AG, Research Division: How should I think about your refinancing plans around that?

We'll certainly take it out by May, and I would say that the interest rate is going to come down. Some of the interest may get passed back to customers. So -- but we could take it out earlier. It just depends and it depends with sort of the agreements that we have with commissions. Kevin Cole - Crédit Suisse AG, Research Division: And so should I follow the bottom line? So for example, if you cut your financing cost from 9% to 5%, we should realize about $0.15 earnings uplift?

We'll get some benefit because some of that financed goodwill. But most of it, I would think, it will help kind of the reverse on rate lag. So I don't believe all of it is going to fall to the bottom line, Kevin. Kevin Cole - Crédit Suisse AG, Research Division: Okay. And then, Dave, I guess, I could try tease out a little more detail around the additional Mancos exposure, because, I guess -- so given that this incremental property already has the drilling permits, should we assume that your partner is an E&P versus a farmer seeking some extra retirement funds?

Yes, yes, that's a safe bet, Kevin. Actually, we'll have -- we obtained our acreage through a deal with a third-party. And also, we are the designated operator then to get these first couple of wells drilled and have that party, as well as a couple other smaller interest owners in the wells. Kevin Cole - Crédit Suisse AG, Research Division: Does your partner add any value per se, like your takeaway ability, your contacts in the area, or anything to benefit the overall Mancos play?

Well, I would call them a good strategic partner. Beyond that, I'm not comfortable really disclosing any additional details. Kevin Cole - Crédit Suisse AG, Research Division: Okay. With the land, is that -- should we consider it's a 160-acre spacing as well or do you have tighter spacing allowed?

Well, I mean, it's in the basin. So the spacing, at least, currently, is the default spacing there, which is just 160 acres, and that's true for the Mancos and the basin. Kevin Cole - Crédit Suisse AG, Research Division: Okay. And then when you've complete the wells, does the offtake go to the partner? Or is there shared agreement or where does the gas flow to?

Yes, I think that's covered under our confidentiality provisions at this point as well, Kevin. Kevin Cole - Crédit Suisse AG, Research Division: Okay. Is the quality of the land at least as good as your current exposure, a little better, a little worse?

Until we drill, we don't know if it's going to be a little better or worse. We believe it's as good or better than our acreage based on what we know and where it is, but until we actually drill it, you never know for sure. Kevin Cole - Crédit Suisse AG, Research Division: Can you say if it's northeast, west or south from where you currently are?

No. Kevin Cole - Crédit Suisse AG, Research Division: Okay. And will the leasehold be held by production?

Yes. It's a large unit, so it's a little more complicated. But yes, it will be. Kevin Cole - Crédit Suisse AG, Research Division: Is the 20,000 acres contiguous property or?

That's kind of a detail I don't really want to disclose either. Kevin Cole - Crédit Suisse AG, Research Division: How about by itself...

It's in the same general neighborhood, let's put it that way. Kevin Cole - Crédit Suisse AG, Research Division: Okay. And then what is the cost for drilling a well these days?

Well, it depends. We're not disclosing our drilling and completion procedures, so we're not going to disclose our well cost either, but we'll probably be in the teens. Kevin Cole - Crédit Suisse AG, Research Division: Like low teens or high teens?

No, I'm not going to say.

Your next question comes from the line of Michael Bates with D.A. Davidson. Michael Bates - D.A. Davidson & Co., Research Division: One last follow-up following Kevin's questions. With this 20,000 potential net acres you could get, how confident are you in earning those additional acres? And is it an all or nothing shot or could you potentially end up with a portion of that 20,000?

Well, in order to earn it all, we have to drill 2 wells in the locations that we originally planned to drill them in. I would say we've got a pretty high degree of confidence we're going to do that, barring some unforeseen circumstances, but we're required to drill and complete the wells. If by chance we drilled the first one and didn't like what we saw and elected not to drill the second one, we wouldn't earn all of that acreage. So it's definitely contingent on drilling and completing the 2 planned wells right now to earn up to the 20,000 acres. If we don't deliver on that commitment, we earn less or if we don't complete either of the 2 wells, we would essentially earn 0. Michael Bates - D.A. Davidson & Co., Research Division: And in what timeframe would you have to drill these 2 wells?

Well, our plan is to drill them back to back, and we're drilling the first one now. So it will only take 40 to 50 days plus to drill and then additional few months to complete. Michael Bates - D.A. Davidson & Co., Research Division: Okay. And then switching topics a little bit, on the CT II discussion from early in the call, can you give us a little bit more color on how you see your options most likely playing out after the contract with Cheyenne Light expires? For example, do you know potential buyers in the region? Any idea as far as potential sale proceeds or?

Yes, I'm not comfortable disclosing numbers, but I would say we're fairly confident that, that asset is either going to be divested or recontracted. I don't think we have any significant risk of a stranded asset. And hopefully, those plans will come to fruition here fairly quickly. We've got a couple of parties we're discussing things with. So I would expect it to happen fairly soon. Michael Bates - D.A. Davidson & Co., Research Division: Soon as in within the next couple of quarters or?

Yes, at least. Probably sooner than that. Michael Bates - D.A. Davidson & Co., Research Division: Okay. And if we made the assumption that the asset did get divested ultimately, what kind of an impact would that have on the segment's earnings?

Off the top of my head, Michael, I don't know. We don't disclose earnings by individual assets. If we did come out and do that, we may have a little more color for you around that. But it really depends a lot on the transaction structure. So it's really hard to speculate on what that could be today.

Your next question is from the line of Andy Smith with Drexel Hamilton.

A couple of questions. One, just following on the E&P transaction that you talked about today. If we thought about that or you guys think about that in terms of acquiring the acreage by drilling, would your cost of acquisition for the acreage, would you say that's average with what's going on in the basin, better or worse?

Well, I'd say -- again, I can't get into the specific deal terms. But this is a drill-to-earn situation. So essentially, we're drilling the wells at our own expense in exchange for not only having a continued interest in the wells, but also the interest earned and the additional up to 20,000 acres. Specifics beyond that, I'm not free to discuss.

Okay. No, understood. And the second question is at the Coal Mining business, with the operations and maintenance expense, which was down again versus first quarter last year, should that start to sort of -- the year-over-year comparison, should that start to moderate as the year goes on? In other words, as you work through your process of addressing the cost last year or should we see continued improvement as the year goes on?

Yes, if you look at kind of where we were towards the end of last year, I think, things -- we had revised our mining plan, really, the whole fourth quarter essentially, we had revised our mining plan, we were mining in the lower overburdened section of the mine during that quarter. So I think you might see a little improvement in the quarter or 2 here. But it's really -- we're settled into normal operations, if you will, with our new revised mine plan and have been for -- this is the second quarter now.

Your next question is from the line of Nick Yuelys with Gabelli & Company.

Can you just go over what approvals are still required to drill in the Piceance and San Juan, and then what -- any sort of updates on timing there? And then if you do get approval this year, is there any potential to drill more than the 2 wells you're drilling?

Yes, the timing, I can't even speculate. 18 months ago, I never would've figured it would take as long as it has to get where we are. But the process is we had to get the environmental assessment completed first, and that literally was approved yesterday afternoon. The BLM still has to approve our pending drilling permits. And that should, theoretically, be quick, now, days, weeks, but I wouldn't bet on that, based on our experience, it's been painfully slow. So we'll see. As far as whether we would drill those wells this year or not, I think it's going to depend on kind of what we see in these first 2. Our original plans and forecast for the year contemplated just drilling 2 wells in the Piceance Basin. If we were to see pretty encouraging results on the first 2, and if gas prices continue to stay firm, it's possible we would move up a couple of wells on our acreage. At this point, I would say it's not probable. And we'll evaluate it based on the information at the time and make a decision. If we have our drilling permits, we would at least have a decision to make. Right now, we don't have one.

[Operator Instructions] And your next question is from the line of Brendan Naeve with Levin Capital.

It's actually Neil Stein from Levin Capital. And your stock has done really well, I was looking, you're actually up 60% since the last equity offering, which kind of leads me to my question, I'm wondering if an alternative way to monetize exposure to E&P would be to sell equity at current prices? Do you -- is that part of your thought process? Or even another alternative might be to use stock as currency in an acquisition.

Yes, I mean, we basically came out last year when we completed the 2 transactions we did, our Enserco sale of our Energy Marketing unit and the Williston Basin sale at E&P and said that we didn't anticipate issuing any other equity, at least through the completion of our Cheyenne Prairie Generating Station that, that cash would essentially finance our major expansion plans through that project at least essentially. I would say that hasn't changed and our opinion about that hasn't changed. Certainly, if we are fortunate enough to have an opportunity for an acquisition, equity would be contemplated, depending on the size of the acquisition. But you never know if you'll have that opportunity or not.

Because I would wonder, even if you're anticipating repaying debt or refinancing debt, it might actually be more accretive to issue equity at these multiples than to issue new debt. Although you'd have to do the math on that obviously.

Yes, I would say our take is, and Tony mentioned this a little bit, we've got a couple term loans coming due, and we have the 9% bonds coming due next year, we're evaluating all reasonable alternatives for how we finance -- refinance that debt.

[Operator Instructions] And it looks like we have no other questions. I'll go and turn the call back over to Mr. David Emery for any closing remarks.

All right. Thank you. Well, thanks everyone for attending this morning. We appreciate your continued interest in Black Hills. And for those of you who are going to be at the American Gas Association Financial Forum this weekend and next week, we look forward to seeing you there. Thank you, and have a great day and a great weekend.

Thank you for your participation in today's conference. This will conclude the presentation. You may now disconnect. Have a good day.