Black Hills Management Discusses Q3 2012 Results - Earnings Call Transcript

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Black Hills (NYSE:BKH) Q3 2012 Earnings Call November 8, 2012 11:00 AM ET


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

Michael S. Worms - BMO Capital Markets U.S.

Timothy M. Winter - Gabelli & Company, Inc.


Good day, ladies and gentlemen, and welcome to the Black Hills Corporation 2012 Third Quarter Earnings Conference Call. My name is Stephanie, and I'll be your coordinator for today. [Operator Instructions]

I would now like to turn the presentation over to Mr. Jerome Nichols, Director of Investor Relations of Black Hills Corporation. Please proceed, sir.

Jerome Nichols

Thank you, Stephanie. Good morning, everyone, and welcome to the Black Hills Corporation 2012 Third 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.

David R. Emery

Thank you, Jerome. Good morning, everyone. Similar to prior quarters, we'll follow our same format. I'll give an update on highlights of the quarter, turn it over to Tony Cleberg for financial updates, and then I'll come back and talk about strategy, in particular going-forward initiatives and things like that, before we open it up for questions.

Starting on Slide 5, for those of you following along in the webcast deck, third quarter highlights. From a business environment perspective, a couple of things impacted our business. July was the warmest month recorded in the continental U.S. But the impact on electric sales was mitigated somewhat by significantly lower humidity in our service territories. So although the heating degree days or cooling degree days, I'm sorry, were much higher, sales aren't increased proportionally because of the lack of humidity.

Similarly, low natural gas prices, which have impacted us for better part of a year plus now, continued to negatively impact our Oil and Gas business.

Highlights in the utilities area for the quarter. All approvals and permits were received for our 132-megawatt Cheyenne Prairie Generating Station. All major equipment has been ordered and we expect commencement of construction next spring. Related to that plant, the Wyoming Public Service Commission approved a construction financing rider, which allows us to make small quarterly rate adjustments during construction, the first of which occurs November 1 of this year. We're considering a similar filing in South Dakota.

In Colorado, our 29-megawatt Busch Ranch wind project and the associated transmission line was completed and placed into service on October 16. A hearing was held related to our Colorado rate case -- Colorado Gas rate case settlement. We anticipate the Colorado PUC to decide on that in the first quarter of 2013. We set a new peak load at Cheyenne Light in July, which was -- we had several peak loads in Cheyenne this last summer.

And then finally, in the utilities area, we're currently considering the filing of a rate case for Black Hills Power. Our last increase for Black Hills Power was in the spring of 2010 in conjunction with the in-service date of our Wygen III power plant. Currently, we're evaluating whether to file a case now and then another one, which would include essentially only the Cheyenne Prairie generating station, or whether we should just wait and file a single case that would coincide with the in-service date of the Cheyenne plant. We're making that determination now and hopefully make a decision here in the next quarter.

Moving on to Slide 6, more highlights from the quarter. We continued to improve results at our coal mine. In the Oil and Gas segment, we closed our Williston Basin asset sale in late September, generating net cash proceeds of about $227 million. During the quarter, we also realized strong production growth on the Oil & Gas side with volumes up 23%.

On the corporate front, with the proceeds from our Williston Basin asset sale, we redeemed $225 million of senior unsecured notes that were originally due in May of 2013. And then finally, in recognition of our strengthened balance sheet and reduced risk profile, both Standard & Poor's and Moody's revised their credit rating outlooks for Black Hills Power and Black Hills Corporation from stable to positive during the month of October.

Slide 7. As I stated a minute ago, we did close our Williston Basin assets sale in September with the $227 million worth of proceeds. There's some details on that transaction here, but that price represented an excellent value for shareholders, and we're very pleased to have that transaction completed.

Moving on to Slide 8. From a financial perspective, we had a strong quarter. Income from continuing operations, as adjusted, was $18.7 million in the third quarter of 2012 versus $13.7 million a year ago. On an earnings-per-share basis, that's $0.42 as adjusted this year versus $0.35 last year, which represents a 20% increase in earnings per share as adjusted quarter-over-quarter.

On Slide 9, the increase in income from continuing operations, as adjusted, over the prior year was driven primarily by our utility and IPP generation in Colorado and improved results at our coal mine.

Now I'll turn it over to Tony Cleberg for the financial update.


Anthony S. Cleberg

Thank you, Dave. Good morning. As Dave described, our third quarter performance produced a strong year-over-year earnings growth. For the shoulder quarter, we're pleased with our earnings from continuing operations as adjusted, and the 20% improvement over the previous year.

Earnings from our utilities, as adjusted, compromised -- comprised 78% of our operating income during the quarter. And also, we recorded a large gain from the sale of the Williston Basin properties that I will discuss later.

Moving to Slide 11. We reconciled our earnings from a continuing operations on a GAAP basis to earnings per share as adjusted, which is a non-GAAP measure. We feel by isolating special items that the resulting earnings per share as adjusted better communicates our relevant performance. This slide displays the last 5 quarters. And during the third quarter of 2012, we had 3 special items. The first special item was a reduction of $0.01 for a non-cash, unrealized mark-to-market gain on our $250 million of de-designated interest rate swaps. This was a result of a slightly increase in the long-term interest rates during the quarter.

The second special item was the reduction for the gain on sale of the Williston assets. Part of the gain was offset by the third special item related to additional incentive compensation attributable to the sale.

Looking at the last year's third quarter, the reconciliation included a $0.63 addition for an unrealized mark-to-market loss on the same $250 million of interest rate swaps. Though considering these special items in the third quarter, our earnings per share as adjusted from continuing operations was $0.42 compared to $0.35 or the 20% increase.

Slide 12 displays our third quarter income statement for 2012 compared to 2011. On later slides, I'll discuss the revenue and operating income in more detail, but here, I'll describe several other noteworthy items that impacted Q3 income statement. The first item was the commencement of operations of the Colorado generation complex at the beginning of the year, which increased not only our earnings, but also increased O&M expenses, property tax and interest.

Another item that I mentioned on the last slide was the $27.3 million pretax gain on the sale of the Williston Basin assets in our Oil and Gas segment. Normally, under full accounts -- full cost accounting method, when you sell Oil and Gas, the entire proceeds would be recorded as a reduction to capitalized costs. However, the SEC provides guidance that if applying the entire proceeds would significantly alter the relationship between capitalized costs, improved reserves, then other alternatives should be considered. In our case, we selected an alternative that compares the fair value of the Oil and Gas properties sold as a percentage of the total fair value of the properties. So the end result is recording a pretax gain of $27 million and about $200 million reduction of our Oil and Gas capitalized costs. This reduction lowers our future depletion rate. Of note, this transaction created a substantially larger economic gain than was recognized from the accounting gain.

Another noteworthy item on this slide is in the quarter, was the nominal mark-to-market gain on the de-designated interest rate swaps compared to a large loss in Q3 of 2011. Another item was an income tax rate of 34% for 2012 compared to a 44% income tax benefit in the previous year.

Last year's rate primarily reflects recording a favorable tax return true up adjustment. Year-to-date, our tax rate is 34%, which is a more normal rate for us.

The last noteworthy item and an item of key importance is our EBITDA. We achieved $95 million of EBITDA as adjusted during the quarter or an increase of 29% over 2011.

Moving to Slide 13. Our total revenue declined in the third quarter compared to 2011. And this was primarily driven by a $9 million decline in our Gas Utilities because of the lower price of natural gas. Excluding the gain on the sale of the Williston Basin assets and the related incentive compensation, our total operating income improves 36% over 2011 driven by improvements in the Electric Utilities, Power Generation and Coal Mining. We are pleased with our progress on cost containment knowing that -- noting that our total O&M expenses declined slightly, driven by sizable increases in our Colorado generation complex and our oil drilling program. These increases were offset by a sizable decrease in our Coal Mining expenses.

O&M expenses for the utility segments were basically flat year-over-year. As you will note in our segment roll up of operating income, we've excluded the impact of a capital lease accounting for our Colorado IPP purchase power agreement. This is an intercompany contract between our Power Generation segment and our Electric Utilities segment. Although lease accounting is required for this purchase power agreement at the segment level by Generally Accepted Accounting Principles, it does not affect our consolidated results. So in this presentation, I've displayed the segment performance, excluding the effects of the lease accounting, which I believe provides a clearer view of segments performance. In our consolidating income statement in our earnings release, we've identified the specific elimination entries for this lease. Also as with all non-GAAP displays, we have included reconciliations to the GAAP amounts later in these slides.

Moving to Slide 11. We display our Utility segment's revenue and operating income. During the third quarter, our operating income, as adjusted for the Electric Utilities, improved $4.2 million or 13% year-over-year. This reflects the benefits of earning returns on the increased rate base offset by 5.8% lower megawatts sold during the quarter. Although we had 30% increase in cooling degree days, we experienced lower humidity that more than offset the impact of the higher number of cooling degree days. Also as a result of identifying certain power plants for retirement, the quarter benefited from a reduction of a major maintenance expense accrual in the amount of $2.1 million.

Moving to Gas Utilities. Our operating income declined by 10% in Q3 compared to 2011. Retail decatherms sold decreased by 5% year-over-year as a result of warmer weather and had the impact of reducing operating income by $500,000 compared to 2011. Our cost-containment efforts kept our O&M expenses flat year-over-year in the third quarter.

So if you think about weather impact for the combined Electric and Gas Utilities, it was a net negative for the quarter in 2012 compared to the prior year.

The next segment, Power Generation. We saw revenue in operating income as adjustment increased due to the operational commencement of the 200-megawatt generating facility in Colorado. Operating income increased year-over-year by $7 million, was primarily driven by the new power plant. We're pleased with the performance in availability and earnings that we continue to see from our Colorado IPP.

Moving to the next segment, Coal Mining. We saw operating income improve by $2.5 million over 2011, primarily driven by the expiration of the train load-out contract that had been producing a loss. Unsold decreased by 29% and the average price increased by 21%. We continued to make progress in reducing our mining costs and the revised mining plan lowered our stripping ratio in the Q3 from 2.5 in 2011 to 1.65 in 2012.

Moving to Oil & Gas on Slide 16. We had a busy quarter. As you are aware, we sold our largest producing properties in the Williston Basin, at a price that we consider full value. We recorded the revenue and expense through these properties through the close date, September 27. During the quarter, operating income, excluding the gain on the sale, declined by $1.7 million from 2011. Overall, third quarter production volume increased by 23% compared to 2011 and increased sequentially from the second quarter by 1%.

The higher production volume reflects increased oil volume of 86% and increased natural gas volume of 6% compared to 2011 third quarter. From a received pricing standpoint, oil increased by 7% and natural gas declined by 28%. From a cost perspective, our O&M expenses increased by $2.5 million over the prior year, while depletion increased $4.7 million. And this was really driven by the increased production.

With the sale of the Williston Basin assets in the quarter, it certainly affects our future earnings. So let me give you some reference points to help you better understand the impact. Margin generated from the Williston assets sold, which is sort of an EBITDA number, is $8 million in the third quarter and $17 million for the Williston assets for the year-to-date. These amounts, as I mentioned, exclude depletion.

Moving to our capital structure. Slide 17 shows our current capitalization. At quarter end, our net-debt-to-capitalization ratio was 51% and improved significantly upon the proceeds from the Williston asset sale. With the additional cash on October 31, we redeemed $225 million of the 6.5 per -- 6.5% notes scheduled to mature in May of next year. We were very encouraged in October because both S&P and Moody's improved our credit outlook from stable to positive.

Moving on to Slide 18. Earnings guidance in the press release, we reaffirmed our 2012 earnings guidance in the range of $1.90 to $2.10. This is for our EPS as adjusted and excludes special items. We implemented a number of initiatives to improve earnings after a slow start in the first quarter and continued to achieve results. So we expect to be in the upper half of the guidance range assuming normal weather.

Achieving the midpoint of our guidance range would result in an 18% year-over-year improvement from 2011.

Looking ahead, Slide 19 lifts our primary assumptions that we made regarding our 2013 earnings guidance. Our 2013 projected range earnings per share from continuing operations is $2.20 to $2.40, exclusive of any special items. We've made assumptions about rate case settlements, normal weather, plant availability, oil & gas prices and production rates and other factors. Overall, we expect a slight improvement in operating income in 2012 -- over 2012 and a notable reduction in interest expense, which contributes to the improved EPS as adjusted for 2013.

A midpoint-to-midpoint increase in EPS as adjusted would result in a $0.30 increase or a 15% improvement year-over-year.

To conclude, we achieved strong financial performance in the third quarter like the improvement that we saw in the Colorado generation in the Coal Mining segments. The Williston Basin asset sale was a huge winner for us and our shareholders. We are encouraged by the increased price of natural gas. It is going up. It was averaged below $3 in the third quarter and we've seen a little higher prices lately. That's certainly encouraging because it has a major impact in our ability to unlock the value in the Mancos Shale properties.

So we feel good about the outlook. And with those comments, I will turn it back to Dave.

David R. Emery

Thank you, Tony. Moving on to Slide 21. We have 5 major strategic objectives focused primarily on being an industry leader in all we do. We want to be a leader in operational performance, earnings growth, earnings upside opportunities and, of course, our track record of annual dividend increases. We also want to improve our credit rating to a BBB flat for senior unsecured credit.

On Slide 22, related to operating performance. This exhibits exceptional performance and customer service O&M cost per customer, electric reliability and safety.

Slide 23 also related to operating performance, demonstrates several things, our superior power plant availability and turbine starting reliability. It also demonstrates that we have one of the most modern generation fleets in the country, and that our power plant construction safety record is fantastic.

Slide 24 relates to earnings growth. We expect strong earnings growth driven primarily by capital spending far in excess of our depreciation in both our utilities and our nonregulated energy operations.

Slide 25. Helping with our earnings growth, our new Colorado Electric wind project, as I mentioned earlier, was placed in service October 16, way ahead of schedule and on budget. Notably, during construction, we had more than 50,000 man hours worked on that project without a single recordable or lost time accident.

Slide 26. Another source of significant future earnings growth is our Cheyenne Prairie Generating Station. That plant is 132-megawatt facility jointly owned by Black Hills Power and Cheyenne Light. It will be constructed in Cheyenne, Wyoming. The construction costs and the associated transmission for that facility are estimated to cost $222 million, and then we've added $15 million for approximate financing cost for the project. That $15 million will be impacted somewhat by our construction financing rider in Wyoming and then what we may choose to do in South Dakota related to a similar filing.

As I mentioned earlier, we've received all permits, we've ordered all major equipment. We expect to commence construction in the spring with an in-service state in the fourth quarter of 2014.

Slide 27. Earnings upside. As demonstrated by our Williston Basin asset sale, our Oil & Gas properties represent a tremendous upside opportunity for shareholders. In the Oil & Gas area, we're focused on proving up the value of our existing properties. We also plan to participate in some limited exploration opportunities, mostly focused on oil plays, at least in the near term. And we want to focus on plays where the reserve potential is large enough to be impactful.

In 2013, we plan to continue to advance our Mancos Shale opportunity in both the Piceance and San Juan basins.

On Slide 28. Demonstrating some of the upside opportunity from Oil & Gas, our existing Oil & Gas properties in the Piceance and San Juan basins have a net resource potential in excess of 2 trillion cubic feet of natural gas. Those are not proven reserves, that's resource potential based on an assumption of 460 well locations. But if you look at that 2.2 tcf of gas, now that's more than 16x our year end 2011 proven reserves of 133 Bcf equivalent.

Slide 29. On dividend growth, we're extremely proud of our track record of increasing dividends for 42 consecutive years, one of the longest streaks in the industry and one, as I mentioned, that we're very proud of.

And finally, on Slide 30, we remain focused on improving our credit rating. And as Tony mentioned and I mentioned earlier, we were able to obtain from both Moody's and S&P outlook improvements to positive from stable for both Black Hills Corp. and Black Hills Power during the month of October.

Finally, on Slide 31, this our 2012 scorecard. We've shown you this for several years. It's really our way of holding ourselves accountable to you, our shareholders. We're making excellent progress on our 2012 goals and objectives. And when we get to the next quarter, we'll show you how we fared for the entire year of 2012 and also lay out our goals and objectives for 2013.

That concludes our remarks today. We'd be happy to entertain any questions.

Question-and-Answer Session


[Operator Instructions] Your first question comes from the line of Kevin Cole with Credit Suisse.

Kevin Cole - Crédit Suisse AG, Research Division

I guess with -- I guess, I'll start with a high-level question of given you guys have made pretty good headway in derisking the business through the sale of Enserco, and I guess, trimming down E&P, at what point would you feel more comfortable to offer some of the longer-term regulated focused growth rate?

David R. Emery

We talked about that in the past. I don't know. We've said that rather than specific growth rate percentages, we lay out our capital spending forecast instead. And we've done that for several years. And while we consider -- continue to consider whether we should put out a specific growth rate or not, I think the capital expenditure forecast kind of speaks for itself.

Kevin Cole - Crédit Suisse AG, Research Division

And I guess, if I look at the CapEx forecast, it does seem reasonable for me to, I guess -- to assume that the EPS growth should be at least the high-single digits to low-double digits between now and 2015?

David R. Emery

I mean, that's a reasonable assumption. I mean, if you look at the capital spending forecast for our utilities there, they are certainly pretty strong for the next several years. I won't comment on a specific number but, I mean, we do expect strong earnings growth and we've said that.

Kevin Cole - Crédit Suisse AG, Research Division

Okay. And I guess with the dividend, what is your thoughts now with, I guess, 18% growth last year, 15% this year? Is there -- are you going to track the dividend with EPS growth at some level ?

David R. Emery

I don't think we have any stated objective of a dividend growth rate percentage. Obviously, our 42-year track record of dividend increases is very important to us. And while we continue to spend a lot of capital, we also recognize that we've made significant improvements in our cash flow and balance sheet. And we typically make the decision to increase dividends and announce that in the first quarter. And we would expect to do that again this coming year. So we haven't made any decisions on the amount of the increase, if you will.

Kevin Cole - Crédit Suisse AG, Research Division

Okay. But we shouldn't expect like an EPS like reset and a growth reset in the dividend?

David R. Emery

We certainly don't have any stated objective of linking earnings growth to dividend growth rates.

Kevin Cole - Crédit Suisse AG, Research Division

Okay. And then, Tony, on the interest expense savings for 2013, are you able to put any numbers around that? Or, I guess, give any visibility on further debt reduction that you plan to take off?

Anthony S. Cleberg

Kevin, I think, the easiest way to look at that is the $225 million that we redeemed, we're probably not going to replace that until towards the end of the year. So you would expect that kind of savings for at least 9, 10 months of the year.


[Operator Instructions] And your next question comes from the line of Michael Worms with BMO.

Michael S. Worms - BMO Capital Markets U.S.

Just a question on the Colorado renewable portfolio standards. Now that you've completed the -- this first phase, the wind project. Are there any other renewable projects that you're looking at down the road?

David R. Emery

We don't have any specific plans to expand our renewables, at least company-owned renewables right now. As you may be aware, Mike, in Colorado, there's the 30% RPS standard, but it's also subject to a 2% rate cap, 2% annual increase related to the addition of renewables. And where we're at now and especially with the low price of natural gas, it appears that it would be very difficult to add additional renewables this time until the price of natural gas increases without triggering that rate cap. So we don't have anything on the drawing board right now. That site, the Busch Ranch wind site, is expandable at least a couple of hundred more megawatts. It's directly interconnected with our system via our own transmission line and so it makes logical sense if we're going to add renewables that that's a great place to do it. But right now, we really can't add anymore and stay underneath our rate cap.

Michael S. Worms - BMO Capital Markets U.S.

Okay. And just for clarification then, what takes precedence over what? Is it the actual 30% number or is it the 2% rate cap that dictates the next level of renewable build?

David R. Emery

It really is the 2% rate cap, Mike. We don't -- essentially, we don't have to meet and can't meet for all practical purposes, the 30% standard and the stairs stepping up to that standard if we would trigger the rate cap. So we'll only add renewable additions to the extent we can stand on the rate cap.


Your next question comes from the line of Tim Winter with Gabelli & Co.

Timothy M. Winter - Gabelli & Company, Inc.

I was wondering if you could talk a little bit more about your process for proving out the reserves. The CapEx numbers on Page 24, what's included for the Oil & Gas business there proven that out? And how are you thinking about potential partners? And just a little more color there, if you could.

David R. Emery

Yes. The specific Oil and Gas CapEx is included in the earnings guidance assumption list there, Tim. It's got a range, but it's like $90 million to $105 million, I think, is listed in there. And basically to prove up our Mancos reserves, and we've talked about this before of the potential there, we think we need several things to happen. First is we want to drill at least 2, maybe as many as 4 more wells in each basin, both the Piceance and the San Juan. Probably we'll focus our efforts on the Piceance first because the gas is richer, and there's also some liquid yield there. So during this period, a low natural gas prices is probably -- the economics are better to drill there first. But we do need to drill several more wells in each location. Basically what that will do is that will prove up the presence of the Mancos and the productivity of the Mancos under most of our acreage block. And then we still have 2 more questions really to answer related to the productivity of that, what our ultimate resource potential is. One is well design. How long should the horizontal lateral be? How many fracture stages should be performed on each horizontal lateral? Our current wells, the 3 that we've drilled have been about a 4,000- to 5,000-foot horizontal lateral with maybe 15 frac stages. There are other operators drilling wells that are 8,000- or 9,000-feet horizontal lengths and as many as 30-plus frac stages. So the combination of the work other operators are doing, plus the wells that we plan to drill, hopefully we'll get a better sense of what's the optimum well design, which answers a lot. It's per well reserves. It also dictates kind of you're finding a development cost.

And then finally, well spacing. Our estimates in here to come to the 2.2 trillion cubic feet of resource potential. Those are based on 160 acres per well. We know that another operator in New Mexico has received approval for 80-acre spacing , which essentially would double that resource number. We also think there's the potential to go as low as 40-acre spacing. So again, those 3 questions, so proving up our acreage, proving up well design and proving up well spacing, those 3 things really need to be done before we ultimately know the true potential of our block. I think that realistically, it's probably going to take at least 2013, maybe part of 2014, to adequately answer those questions. And at that point, then we would be considering alternatives, whether to keep it all and drill it, whether to bring in a partner, whether to bring in a partner for one basin and maybe not the other. We could sell a portion of it. All those alternatives, we want to leave open until we fully understand the true potential of our property.


[Operator Instructions] A follow-up question comes the line of Kevin Cole with Credit Suisse.

Kevin Cole - Crédit Suisse AG, Research Division

I just want to maybe dig a little deeper in the 2013 guidance. And so for the power and coal, I noticed in the comment at the conversation in the guidance was a little bit lighter than normal. Are you expecting power to be somewhat a steady-state now with the Colorado project fully in service? And so '13 should look a little bit like '12? And then for the coal side, what should we think about for improvement off of 2012 numbers?

Anthony S. Cleberg

I would say in the Power Generation, the one thing we got a little bit of an extra kicker this year just because of the way the property taxes get graduated in. So flat to slightly down, that's how to think about Power Generation, just for the property tax issue. The second one is on Coal Mining. We expect continued improvement there because we really didn't get the implementation of our revised mine plan until into the third quarter. So we expect year-over-year to continue to improve in that area.

Kevin Cole - Crédit Suisse AG, Research Division

And then, I guess, with E&P, with the production of 9.3 to 10.3 Bcfe. I guess, given the asset sale, I guess, my hedge numbers are a little off. Can you give me some color on the -- of those numbers expectations? Do you expect a split between oil and natural gas and for 2013, '14, '15, what's your hedge profile looking like these days?

David R. Emery

Well, if you look at the percentage of production, Kevin, if you look at what we did for the third quarter and then we also disclosed how much oil was related to the assets that we sold, you can get a pretty good handle on kind of what the Oil & Gas split is, at least for now. We don't anticipate a radical change in that, basically the big change is going to be the asset sale on the Williston. And we put out both our total expected production number for next year, and we've also put out what we sold through the 9 months of 2012. Yes, that's pretty much the expectation.

Kevin Cole - Crédit Suisse AG, Research Division

Then what is the hedge profile for '14 and '15?

David R. Emery

Hedging results will be out, including some of the revisions. We had some hedges on the crude oil we sold, which we closed out and did some other hedging during the quarter. That will be updated in the Q, which will come out later today.

Kevin Cole - Crédit Suisse AG, Research Division

Okay. And then, I believe, last quarter, you were bracing us for a ceiling test? Did the recovery in that surpass, just kind of take that issue away?

Anthony S. Cleberg

It's is really the sale of the Williston Basin assets and reducing the cost basis by $200 million. We got a total of 2 27. So we took part of that gain and that $200 million reduction in our cost basis really eliminates the need for any ceiling test.

Kevin Cole - Crédit Suisse AG, Research Division

Okay. And then with the -- I noticed the normal slide with the CapEx by year, by project, is that no longer being provided? It's just not in the earnings handout.

David R. Emery

We don't have it in here.

Anthony S. Cleberg


Kevin Cole - Crédit Suisse AG, Research Division

Will it come out for EEI?

David R. Emery

We haven't decided that yet.

Kevin Cole - Crédit Suisse AG, Research Division

And then for the regulated CapEx, can you give me an idea of -- I guess, 2 questions here is what is the shaping of the Prairie Generation for 2013, given that the orders have been put in place? And so should the CapEx be rather chunky towards the beginning of the year so you have greater realization of the AFUDC in your earnings? And then as well, what is the shape of the CapEx during the project build cycle?

Anthony S. Cleberg

I don't know that we've laid that out yet, formally. I mean, we have it internally. I would just mention again that on the Prairie Generation Station, we've identified the actual cost, the $222 million and then the $15 million of financing. And with Wyoming giving us the rider, in effect, what you have is you have 60% of those assets where we will receive the financing cost during construction. And we're going to go forward and talk with South Dakota to try to get the same kind of an arrangement. So AFUDC would not be recorded on that 60%. But in fact, what we had received is we would receive revenue and income as we're constructing the asset that would offset any interest expense. And it's actually better than the interest expense. That help?

Kevin Cole - Crédit Suisse AG, Research Division

Yes, it kind of does, yes. And so, I guess, given that the project is located in Wyoming, is the first half or, I guess, the good chunk of the spending at the beginning kind of fit under the CWIP portion, so you're getting more cash returns for the fund of the project?

David R. Emery

Well, 60% of the customer ownership essentially is going to be in Wyoming. So that's the portion that will be covered by the rider. Roughly 40% of the asset is going to be dedicated to serving South Dakota customers, and we're still evaluating whether to file a similar rider for construction financing in South Dakota.

Kevin Cole - Crédit Suisse AG, Research Division

So if I'm thinking again about the spending, should the project spend cycle look a lot like the Colorado projects if I look at the lumpiness of the spending...

David R. Emery

Yes. I mean, it's going look like a gas project. Upfront, all you're doing is making progress payments on turbines and things like that until you actually start taking delivery of major components.


With no further question in queue, I will turn the call over to Mr. David Emery for closing remarks. Please proceed.

David R. Emery

Well, that concludes our call this morning. Thank you, all, for your interest in Black Hills. We appreciate your attendance on today's call. Have a great day.


Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect, and have a great day.

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