Jerome Nichols - Director of Investor Relations & Corporate Communications David R. Emery - Chairman, Chief Executive Officer and President Anthony S.

Cleberg - Chief Financial Officer, Principal Accounting Officer and Executive Vice President

Kevin Cole - Crédit Suisse AG, Research Division

Thank you, Bree. Good morning, everyone, and welcome to the Black Hills Corp.

2012 Second 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 the call over, 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.

Thanks for joining us today. Consistent with prior calls, I will give a quick update on the quarter, followed by a financial update by Tony and then I will come back on for an overview of our go-forward strategy.

For those of you following along on the webcast presentation, I will be starting on Slide 5. We had a strong second quarter.

Earnings per share as adjusted were up 55% compared to the same quarter in 2011. Several items impacted our business during the quarter, we had record-breaking warm weather across our utility territories, which hurt our Gas Utilities in the spring and helped our Electric Utilities during June.

Lower natural gas and crude oil prices impacted our Oil & Gas business, and multiple wild fires in Wyoming, Colorado and South Dakota impacted both our Utility and Oil and Gas operations. We turned off gas service to several Colorado communities, we shut in Oil and Gas wells in the Piceance basin in Colorado and we had impacts to portions of our electric transmission system here in the Black Hills.

But in total, there was minimal impact to operating income from the fires during the quarter. On the Utilities side, our Cheyenne Prairie Generating Station received approval on July 31 from the Wyoming Public Service Commission.

At Colorado Electric, our new plant, which was placed in service on January 1, continued to operate well with greater than 91% availability during the quarter. New rates were implemented as compared to the prior year.

Also at Colorado Electric, our new 29-megawatt wind project is 80% complete and on schedule and on budget. Cheyenne Light on July 1 received approval to implement a $4.3 million increase in electric and natural gas rates, and we set new peak loads in June for both Colorado Electric and Cheyenne Light.

And it is notable that our prior peaks in both of those utilities were in mid-July in 2011, so having new peaks engine in June and 2 utilities was a little unusual. We've also, in fact, set a couple more peaks at Cheyenne Light during the month of July and came very close to setting a new peak at Black Hills Power during July as well.

We've been very warm. The Power Generation segment, our new plant in Pueblo, Colorado continues to operate very well with greater than 97% availability during the quarter.

Moving on to Slide 6, Coal Mining. The mine commenced operations for our revised south to north mine plan, which will reduce overburden stripping ratios and thus reduce our mining costs for the next several years.

Our Oil and Gas segment production volumes increased 23% quarter-over-quarter compared to last year. Crude oil was up more than 50%.

In our Oil and Gas business, due to lower natural gas prices, we recorded a $17.3 million after-tax noncash ceiling test impairment. We extended $150 million term loan for another year, taking advantage of very low short-term interest rates, and the Board of Directors approved a quarterly dividend of $0.37 a share.

We've announced other key new subsequent to the end of the second quarter, including the July 30 filing of our Electric Resource Plan in Colorado, and I'll talk more about that later. And yesterday's announcement of our plans to comply with federal and state emissions regulation and our power plant fleet, and I'll also elaborate more on that later as well.

Moving on to Slide 7. Second quarter income from continuing operations as adjusted was up 72% from $8.8 million in 2011 to $15.1 million in 2012.

As I said earlier, the earnings per share as adjusted was up only 55% due to the dilutive effect of our late 2011 equity issuance. Slide 8 illustrates the change in income from continuing operations as adjusted from the same quarter last year.

The increase was driven primarily by our Electric Utilities, predominantly by our new Colorado power plant and its associated rate increase, our Power Generation business, which also is related to the new power plant in that unit and our Coal Mining segment. Those increases were partially offset by decreases in our natural gas utilities driven by a record warm weather and oil and gas results primarily as a result of lower gas prices.

Next, I'll turn it over to Tony for the financial revenue. Tony?

Thank you, Dave. Good morning.

As Dave described, our second quarter performance improved significantly over the previous year. For a shoulder quarter, we're very pleased with our EPS as adjusted and the 55% improvement over the previous year.

Excluding the ceiling test impairment, earnings from our Utilities compromised 84% of our operating income. So with the decline in the Gas Utilities due to weather, we achieved solid utility performance.

On a GAAP basis, we had some large noncash charges that I'll describe later. Moving to Slide 10, we've reconciled earnings from continued operations on a GAAP basis to earnings per share as adjusted, which is a non-GAAP measure.

We feel by adding and subtracting special items to the GAAP earnings, the resulting earnings per share as adjusted better communicates our relevant performance. This slide displays the last 5 quarters, and during the second quarter of 2012, we had 2 noncash special items.

The first special item was the addition of $0.23 for a noncash unrealized mark-to-market loss on our $250 million of interest rate swaps. This is the result of continued decline in long-term interest rates.

The second special item was the addition of a noncash ceiling test impairment charge recorded to lower the value of our oil and gas properties. The decline in the value was driven by low natural gas prices.

So considering these 2 special items, the quarter's earnings per share as adjusted from continuing ops was $0.34 compared to $0.22 for 2011. Looking at last year's second quarter, the reconciliation included a $0.13 addition for the unrealized mark-to-market loss on the same interest rate swaps.

Slide 11 displays our second quarter income statement for 2012 compared to 2011. On later slides, I'll discuss the revenue and operating income in detail, but here, I'll describe several other noteworthy items that impacted Q2 income statement.

The first noteworthy item was the commencement with the operations for the Colorado generation complex at the beginning of the year, which increased not only our earnings, but also increased our O&M expenses, property tax, interest expense. Two other noteworthy items that I mentioned on the last slide were the ceilings test impairment which is a pretax $26.9 million, and then the mark-to-market on the de-designated interest rate swap.

Another noteworthy item was the income tax rate of 38%, which was a benefit during the quarter rather than an expense because of the book loss in the quarter. This compares to a 44% income tax expense in 2011 that included a state income tax true-up.

Year-to-date, our tax rate is 35%, which is a more normal rate for us. The last noteworthy item and an item of key importance was the increased EBITDA.

We achieved a $90 million EBITDA during the quarter, which is an increase of 30% over 2011. On a year-to-date basis, our EBITDA increased 24%, so we're quite pleased with the continued improvement and expect this level of improvement to continue throughout the year.

Moving to Slide 12. Our total revenue declined in Q2 compared to 2011, and this was primarily driven by a $30 million decline in Gas Utilities.

Excluding the ceiling test, our total op income improved 31% over 2011 driven by improvements in the Electric Utilities, Power Generation and Coal Mining. We are pleased with the progress on cost containment, noting that our O&M expenses were up only slightly driven by a sizable increase to support our Colorado generation complex and an offsetting sizable decrease in our Coal Mining costs.

O&M expenses in our Gas Utilities segment and our Oil and Gas segment were basically flat year-over-year. Slide 13 displays our Utilities segment, revenue and operating income.

The Electric Utilities' operating income in Q2 improved by $10.1 million or 45% year-over-year, reflecting the benefits of earning returns on an increased rate base and increased retail megawatts sold driven by warm weather. Overall, retail megawatts sold during the quarter increased by 4.5% compared to 2011.

The weather improved operating income by approximately $2.5 million compared to 2011. Moving to Gas Utilities, operating income declined by 43% in the second quarter compared to 2011.

Retail decatherms sold decreased year-over-year by 32% as the result of a warmer weather and have the impact of reducing operating income by $2 million compared to 2011. So if you think about the weather impact for the combined Electric and Gas Utilities, it was a relatively small, net positive for the quarter.

The next segment, Power Generation, we saw operating income increase due to the operational commencement of the 200-megawatt generating facility in Colorado. Operating income increased year-over-year by $7.5 million, and was primarily driven by the new facility.

We were pleased with the performance and availability and earnings that we continue to see at our Colorado IPP. Moving to the next segment, Coal Mining.

The operating income improved by $2.4 million over 2011, primarily driven by the expiration of the train load-out contract that had been producing a loss. The tons sold decreased by 20%, and the average price increased by 6%.

We continue to make progress with reducing our mining costs and expect to continue to improve, most particularly with implementing the revised mine plan, which will lower our stripping ratio during the next couple of years. Moving to Oil and Gas on Slide 15.

During the quarter, operating income, excluding the ceiling test, declined by $3.7 million from 2011. Overall, Q2 production volume increased by 23% compared to 2011 and increased sequentially from the first quarter by 4%.

We are pleased to see the higher production with our oil volume sold increasing 54% and our natural gas volume sold increasing 16% compared to 2011. From a received pricing standpoint, both oil and natural gas declined.

Oil prices declined by 4%; natural gas prices declined by 27%. From a cost perspective, we kept our O&M expenses almost flat with 2011, while depletion increased $5.4 million.

Some of the increased depletion related to the higher reduction, but the quarter also included a $3.4 million catch-up adjustment to reflect our depletion rate for the year. The depletion rate increased because we deferred drilling in the Mancos Shale, which has the impact of lowering our estimated reserves at year end.

Also much of the current capital spending relates to the Bakken play where drilling costs are substantially higher than our average depletion rate. So with the current low natural gas prices, we are focusing on building substantial value in our oil reserves.

Moving to our capital structure on Slide 16, it shows our current capitalization. Our net debt-to-capitalization ratio at quarter end was 55%, which is in line with our target.

During the quarter, we extended a term loan for the year -- for a year at LIBOR plus 110 to take advantage of the low short-term rates. We feel our capital structure is in good shape.

On Slide 17 and in the press release, we reaffirmed our 2012 earnings guidance in the range of $1.90 to $2.10. This is for EPS as adjusted and excludes special items.

We're implementing a number of initiatives to improve earnings over the remainder of the year and started to gain traction in May and June, so we are comfortable with the guidance range. Achieving the midpoint of our guidance range will result in an 18% year-over-year improvement.

As a reminder, without a stronger recovery in natural gas prices, we may be impairing assets for ceiling test in the third quarter and possibly the fourth. If we flatline the natural gas price at $2.50 per Mcf at Henry Hub prices, the aggregate impairment could range from $45 million to $55 million by year end, of which $27 million was recorded in the second quarter.

These are noncash charges and have not been included in our guidance for EPS as adjusted. As a reminder, the ceiling test calculation assumes a flat price over the life of the reserves, even though history would indicate that there will be fluctuations and sometimes sizable.

So to conclude, we achieved strong financial performance in the second quarter and liked the improvement that we saw from the Colorado generation and Coal Mine. The weather was a small net positive during the quarter, the warm April depressed Gas Utilities and the warm June enhanced the Electric Utilities performance.

Natural gas prices have improved from Q1 but remained at the very low level. Overall, we are encouraged by the second quarter performance, and we will be filing our 10-Q later today so that information will be available.

And with those comments, I'll turn it back to Dave.

All right. Thank you, Tony.

Moving on to Slide 19 and talk about long-term strategic objectives, which remain essentially the same. We intend to continue our focus on growth from our core businesses and especially our Utilities within the Midwest and Rocky Mountain regions.

We want to improve profitability in all of our businesses and we're going to do that by growing through investment and rate-based assets and ensuring timely recovery of that invested capital on our operating expenses. We want to focus on proving up the tremendous potential value of our existing Oil and Gas assets, particularly in the Mancos Shale; selectively growing our IPP business as opportunities become available; and especially through controlling costs via continuous improvement and operational excellence initiatives.

As Tony said, we want to target our long-term debt-to-cap ratio of less than 55% and improve our long-term -- improve our investment credit ratings. Slide 20 illustrates our planned capital investments by business segments for 2012 through 2014 as disclosed in our 10-Q.

It's very notable that this forecast includes more than $1.2 billion in growth capital over that 3-year period. Slide 21 provides additional detail on our capital spending plans, including details on several announced projects and also planned spending for some of those projects beyond 2014.

Moving on to Slide 22, our 29-megawatt Colorado Electric wind project is progressing on budget and on schedule for completion prior to year end. At the end of June, construction was 80% complete and is continuing to proceed as planned.

Slide 23 is an update on recent regulatory proceedings in our Utilities. Our Cheyenne Prairie Generating Station is progressing according to plan.

During a hearing on July 31 with the Wyoming Public Service Commission, they approved our Certificate of Public Convenience and Necessity for the $237 million, 132-megawatt gas-fired facility. Prior to the hearing, we reached a settlement with the Wyoming Office of Consumer Advocates, who was the only intervenor in the case.

That settlement included a construction work in progress rider in which we proposed -- which we propose instead of the traditional allowance for funds used during construction, or AFUDC, that effectively would have reduced the construction cost from $237 million to $222 million. During the hearing, while the Commission noted those provisions in the settlement agreement, they chose to approve the CPCN, which allows us to proceed with the project, but they indicated a preference to consider the CWIP rider and the total construction cost figure in a separate proceeding.

We expect to make the related filing with the Wyoming Public Service Commission during the third quarter. It's important to note that the Wyoming approval covers Cheyenne Light share of the joint plant and the Black Hills Power share of the plant on behalf of its Wyoming customers only.

South Dakota does not have a CPCN process. Though historically, for power plants constructed on behalf of Black Hills Power South Dakota customers, we usually file a rate case with an effective date equal to the commercial operation date of the new facility just as we did in 2010 with the Wygen III plant.

However, new legislation was approved in South Dakota this year that provides for a rate phased-in process similar to the CWIP rider we proposed in Wyoming. We intend to propose a similar CWIP rider in South Dakota, which will look a lot like the one we intend to file in Wyoming, and we'll be working through that process with the South Dakota Commission permission later in the year.

Finally, related to the Cheyenne plant, we received our industrial siting permit on July 10 and we hope to get our air permit approvals during the third quarter, after which time we would anticipate commencing construction. In other regulatory highlights, in late June, the Wyoming Public Service Commission approved our $4.3 million rate increase for Cheyenne Light.

And finally, on July 30, we filed an Electric Resource Plan with the Colorado Public Utilities Commission for our Colorado Electric Utility. That plan proposes a 40-megawatt simple cycle gas turbine to replace the W.N.

Clark 42-megawatt coal-fired facility, which will be retired at year end 2013 to comply with the Colorado Clean Air-Clean Jobs Act. The resource plan also addresses our renewable generation needs to meet Colorado's renewable energy standard.

We have not yet filed for approval of a CPCN for the 40-megawatt gas-fired plant, but we anticipate doing so as we work our way through the electric resource plant process with the Colorado PUC. We expect to receive the necessary approvals to complete construction and have the plant in service in late 2016.

Slides 24 and 25 address the impact on our power generation fleet of U.S. Environmental Protection Agency in State of Colorado emissions regulations.

We've been discussing with you possible courses of action related to these regulations for more than a year. I plan to cover our compliance plans in some details today, and after that don't intend to mention them much during future calls because we will be essentially compliant if we execute on our plan.

Key regulations which impact the operations of our plant includes the EPA industrial boiler MACT, their utility MACT and regional hays regulations, as well as the Colorado Clean Air-Clean Jobs Act. Yesterday we issued a press release announcing our short- and longer-term plans for the Power Generation facilities impacted by these various emissions regulations.

For Black Hills Power, we announced plans for 3 coal-fired facilities: Ben French, a 25-megawatt facility in Rapid City, South Dakota, we intend to suspend operations there on August 31 and retire the facility in March 2014, which is the compliance date of the EPA's industrial boiler rule. For Osage, a 35-megawatt plant in Osage, Wyoming, operations have been already suspended on October 1, 2010.

We intend to retire the facility in March 2014. For Neil Simpson I, a 22-megawatt plant located at our Energy Complex near Gillette, Wyoming, we intend to operate the facility until it is retired in March 2014.

We intend to use Black Hills Power share of the Cheyenne Period Generating Station to replace about 55 megawatts of the 82 megawatts of plant retirements we've announced. In the near-term, until the new Cheyenne facility has placed in service, we expect to use available purchase power resources to fill our capacity shortfall.

At Colorado Electric, we announced our intent to suspend operations at several older facilities there also. We will suspend operations at the 42-megawatt W.N.

Clark coal-fired plant in Canyon City, Colorado at year end 2012 and retire the plant by year end 2013. We also intend to suspend operations at the Pueblo #5 and #6 gas-fired steam units which totaled 29 megawatts at year end 2012.

In Colorado, we intend to use the proposed 40-megawatt gas-fired unit included in our recently filed electric resource plan to provide replacement capacity in Colorado effective in 2016. In the meantime, we expect to purchase power as needed prior to completion of that 40-megawatt facility.

All the plants to be retired have been in service for 50 to 65 years or so. They're long-term efficient and economic operation, I think, is truly a credit to the employee teams who operated them for decades.

Nearly 20 employees will be impacted as we suspend our operations at Ben French and W.N. Clark later this year, and I'd sincerely want to thank them for their years of service.

Regarding the EPA's 2012 Utility MACT Rule, which has a final compliance deadline of April 2015, we believe the remainder of our generation fleet will be compliant. Minimal changes have already been tested at Neil Simpson II and our Wygen units I, II and III.

Related to the EPA's Regional Haze Rules, we expect only Neil Simpson II to possibly be impacted. Based on recent EPA Regional Haze decisions, we're not forecasting any significant capital investment for Neil Simpson II in order to be compliant.

If we do have to invest capital there, the worst case scenario could potentially cost up to $52 million, but we view that as highly unlikely and we have not included any related capital in our 3-year capital spending plan. Moving on to Oil and Gas on Slide 27.

Our Oil and Gas strategy remained consistent, although our capital expenditures may vary depending on oil and gas prices and the pricing environment going forward. One of our primary objectives is to further define the tremendous potential of our Mancos Shale gas holdings in the San Juan and Piceance basins.

We've been talking about that for well over a year. Based on low natural gas prices, currently, we made the decision to defer our 2012 San Juan Basin Mancos Shale program.

We will focus our efforts instead in 2013 on the Piceance basin where liquid contents are higher and the BTU content of the gas is higher as well. We intend to continue to develop and expand our existing Bakken shale position in the Williston basin.

And although we have a minority non-operated working interest position in the play, it's a very economical oil play with substantial undeveloped value. We'll continue to pursue new crude oil opportunities that have the impact or potential to impact reserves in a meaningful way, and we're really focused on continuing to manage our existing properties as cost-effectively as possible.

On Slide 28, as I mentioned previously, we continue our efforts to prove up those substantial Mancos Shale gas potential of our properties. This provides an update on that activity.

Slight revision to some of the reserve numbers at the bottom of the page. Bottom line is our 2011, 2012 test wells, all 3 of them met or exceeded our expectations and we're very excited about the continued future of the play.

Slide 29 provides an update to our 2012 strategy scorecard for second quarter activity. Again, this scorecard is our way of setting forth our goals for you and then holding ourselves accountable to you, our shareholders, for accomplishing those goals.

Finally, In conclusion, on Slide 30. The second quarter was an exciting quarter for us.

We substantially improved our earnings from continuing operations as adjusted, we advanced several key strategic growth initiatives and we've reaffirmed our May 2012 earnings guidance of $1.90 to $2.10 per share as adjusted. That concludes our remarks.

I would be happy to entertain any questions now.

I guess, first on the regulated growth. Can you help me make sure I'm fully understanding where the Black Hills Power Cheyenne Light is versus the needed approvals from Wyoming and South Dakota.

And so, first, I guess, is it correct that basically you've reached -- you received all the approvals required from Wyoming to move forward on the project? And in South Dakota, there is no, I guess, pre-approval process, but given the EPA closures and I guess that should satisfy the need component?

And maybe the CWIP ask will help -- will kind of be like a pre-approval process?

Yes, essentially we have an approved CPCN in Wyoming for both Cheyenne Light and Black Hills Power. We would like to go ahead with CWIP rider which will essentially allows us to gradually increase rates during construction, avoid a little bit of the total capitalized cost because we're not capitalizing the interest for construction.

And I think we got generally a good feeling about that proposal, but the Commission would really rather deal with that in a separate proceeding where they can focus on that and only that. So we intend to file that.

So Wyoming is pretty much taken care of. We have the go-ahead that we need to start construction once we get our air permits, which we hope to get this quarter.

Now South Dakota, as I said before, there is no CPCN or pre-approval process there. We believe that the demonstration of need is very simple when we're retiring 82 megawatts of coal-fired generation, so we're not concerned about proceeding with the project.

However, similar to Wyoming, we like the idea of doing some kind of a construction work in progress rider in South Dakota in the last legislative session really approved a piece of legislation that would allow us to do that. So we intend to pursue it and we think it would be favorably received.

You'll never know until you make the actual filing what we believe they'll be supportive of that. It certainly mitigates the rate shock to rate payers of having one large increase all at once and allows again to reduce the capitalized cost of the whole project.

We would probably proceed even in the absence of that hard to say until we were to have any kind of an adverse ruling. But we have what we need to proceed.

We intend to proceed with the project and hopefully, we can work our way through these CWIP riders in both states which will just make the whole rate case process a little smoother. You made the comment, Kevin, that perhaps the South Dakota one would be a pre-approval of sorts.

There is no pre-approval statute really in South Dakota, but you certainly wouldn't think they would allow you to raise rates for a project if they weren't going to allow the project and rate base after its completion. So I guess in some aspects, that would be a form of pre-approval.

Great. And then on the funding of this project, I guess given your balance sheet just in pretty healthy today, is it reasonable to assume that you'll take a similar approach as you did with the Colorado projects where you'll seek to take the dilution closer to when the projects come into service, or do you see other growth projects being adequate enough that you can kind of issue the equity sooner?

Well, I think as we said previously, particularly upon the sale of our Enserco Energy Marketing business that we expect to begin well through this year and hopefully even a little farther before we have to issue additional equity. I think during construction, we've had conversations with rating agencies and I don't think for a regulated facilities, they have a problem with letting that debt-to-cap ratio creep up a few percentage points, 58%, 59% when it's for regulated projects.

And then we would look -- if we have to do equity financing, we would look to do it opportunistically in that during construction or late construction phases as needed. But certainly, we don't want to do it any sooner than necessary.

Okay. And then I guess moving to the E&P business.

Is it correct to assume that the dollars that you're once allocating towards the Mancos development are now being aimed, I guess, towards the more relevant Bakken oil play today?

Yes, we haven't announced the change in our E&P capital spending for the year. We do have some other projects relatively small and probably not worth mentioning by name, but we do have several other projects that will use up a little bit of that capital, and then certainly the Bakken development continues to consume capital as well.

So when you say pursue new crude oil opportunities, is that the Bakken play?

No, not necessarily. We're always looking for new projects and particularly, crude oil projects kind of like everyone else in the industry.

But we do have some opportunities around some of our existing operations, say, in the Powder River basin and elsewhere that we might focus a little more attention on because they're good economical crude projects.

So the strategy here to develop that for the economics of today or to prove it up than to maybe monetize it?

Well, clearly, we're developing it for the economics of today. I think we've demonstrated with other businesses that if we can get a very strong value for our business or an asset that we're willing to divest it and capture that value for shareholders, and so we'll continue to do both, I guess.

And then I guess on the impairment test for the rest of the year, you mentioned the $2.50 NYMEX price?

Yes.

Why are you using that price given that third quarter looks to be $2.90, the fourth quarter looks to be $3.10, so the full year will be $2.75, and even in '13, we're starting to see $3.62, then '14 we're seeing good recovery $4 range again? I guess why are you using such a low number for that test?

Well, just from a projection standpoint, we still don't know what the gas price will be even though you have a strip in the futures market. So we just use $2.50 to ballpark where we'd end up, Kevin.

Essentially gives you hopefully a worst case scenario.

Yes. What sort of sensitivity if that $2.50 ended being closer to $2.75?

Do you have that by any chance?

We don't. No, we don't.

We don't really have that, Kevin.

Do you think that would materially change the number, or if we're just kind of same ballpark?

No, it will come down.

Okay. And then I guess, David, just kind of an I guess overall kind of conversation on the growth profile of the business.

I guess, now since you've -- I guess you've sold the pesky energy trading business and your earnings are I guess, for the most part, locked in now through 2015 with the advancements of the CapEx program on the last week or so, would you consider kind of giving an EPS growth rate to help us kind of I guess regauge for your now, I guess, higher-quality consolidated business is going?

That's something we would consider, Kevin, and historically, we haven't done that. We just typically give our guidance in November for the subsequent year, and we've contemplated making changes to that but not too seriously at this point in time.

We do lay out in kind of great detail our capital spending plans, which should provide the information necessary to calculate that growth rate.

All right. Well, thank you.

Thanks for your attendance today. We sincerely appreciate it, and thanks for your continued interest in Black Hills Corp.

And we're excited about the quarter and looking forward to the rest of the year. Have a great day.