Black Hills Corp (BKH) 2012 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Black Hills Corporation 2012 third quarter earnings conference call.

My name is Bethany and I will 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.

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 two of the investor presentation on our website, and our most recent, form 10-K and 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. Similar to prior quarters we will follow our same format. I will give a update on highlights of the quarter, turn it over to Tony Cleberg for financial updates, and then I will come back on and talk about strategy and particular going forward initiatives and things like that before we open it up for questions.

Starting on slide five 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 in recorded in the continental US. But the impact on electric sales was mitigated somewhat by significantly lower humidity in our service territories.

Although the heating treeing days or cooling degree days were much higher, sales aren't increased proportionally because of the lack of humidity. Similarly, low natural gas prices, which can have impacted us for a better part of a year-plus now, continue 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 writer, which allows us to make small quarterly rate adjustments during construction, the first of which occurs November 1st of this year. We are 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 16th. 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 peek loads in Cheyenne this summer. And then finally, in the utilities area, we are 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 3 power plant. Currently, we are 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 are making that determination now. And hopefully make a decision here in the next quarter. Moving on to slide six, more highlights from the quarter.

We continue to improve results at our coal mine. In the oil and gas segment, we closed our Williston Basin assets sale in late September, generating net cash proceeds of about $227 million. During the quarter, we also realized strong production growth on the oil and gas side, with volumes up 23%.

On the Corporate front, with the proceeds from our Williston Basin assets 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 Blake Hills Power, and Black Hills Corporation from stable to positive during the month of October.

Slide seven, as I stated a minute ago, we did close our Williston Basin assets sale in September with the $227 million worth of proceeds. There is some details on that transaction here, but that price represented an excellent value for shareholders, and we are very please today have that transaction completed.

Moving on to slide eight, from a financial perspective, we had a strong quarter. Income from continuing operations as adjusted was $18.7 millionin the third quarter of 2012, verses $13.7 milliona year ago. On an earnings-per-share basis, that's $0.42 as adjusted this year, verses 35 last year, which represents a 20% increase in earnings per share as adjusted quarter-over-quarter.

On slide nine, the increase in income from continuing operations as adjusted over the prior year was driven primarily by our utility and I.P.P. generation in Colorado and improved results at our coal mine. Now I'll turn it over to Tony Cleberg the financial update. Tony.

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 are pleased with our earnings from continuing operations as adjusted in the 20% improvement over the previous year. Earnings from our utilities, as adjusted and 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 ops -- operations on a GAAP basis to earnings-per-share as adjusted, which is a non-GAAP measure. We feel by isolating special items at the resulting earnings per share as adjusted better communicates our relevant performance.

This slide displays the last slide quarters, and during the third guarder of 2012, we had three special items. The first special item was the reduction of $0.01 for a non-cash unrealized market-to-market gain on our $250 million of dedesignated interest rate swaps. This was the result of a slightly increase in the long-term interest rates during the quarter.

The second special item was the reduct -- 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, of the reconciliation included a $0.63 addition for an unrealized market-to-market loss on the same $250 million of interest rate swaps.

So considering these special items in the third quarter. our earnings-per-share as adjusted from continuing operations was $0.42 compared to $0.35,more than a 20% increase. Slide 12 displays our third quarter income statement for 2012 compared to 2011. On later slides, I will discuss the revenue and operating income in more detail, but here I'll describe several other noteworthy items that impacted packeted 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 I mentioned on the last slide was the $27.3 million pre-tax gain on the sale of the Williston Basin assets in our oil and gas segment.

Normally, under full accoun -- full-cost accounting method, when you sell oil and gas, the entire proceeds would be recorded as a reduction to capitalized costs. However, the SECprovides guidance that if applying the entire proceeds would significantly alter the relationship between capitalized costs and proved reserves, then other alternatives should be considered.

In our case, we select an alternative that compares the fair value of the oil and gas properties sold, as a percentage of the total fair value of the property. So the end result is recording a pre-tax gain of $27 million, an about $200 million reduction of our oil and gas capitalized costs. This reduction lowers our future depletion rate.

Of note, this transaction creates a substantially larger economic gain than was recognized from the accounting gain. Another noteworthy item on this slide is in the quarter, was the market-to-market gain on the dedesignated 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, not -- 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 decrees 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 have excluded the impact of a capital lease accounting for our Colorado IPPPurchase Power Agreement.

This is an inter-company contract between our power generation segment and our electric utility segment. Although lease accounting is required for this purchase power agreement at the segment level, by generally accepted accounting principles, it does not effect our consolidated results.

So in this presentation, I have 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 have 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 segments, revenue and operating income. During the third quarter, our operating income as adjusted for the electric utilities improved proved $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 retirements, 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 the 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 utilities, it was a net negative for the quarter in 2012 compared to the prior year.

The next segment, Power Generation, we saw revenue and operating income as adjusted increase due to the operational commencement of the 200 megawatt generating facility in Colorado. Operating income increased year-over-year by $7 million, and was primarily driven by the new power plant. We are 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 exploration of the train load out contract that had been producing a loss. Tons sold decreased by 29%, and the average price increased by 21%. We continues to make progress in reducing our mining cost, and the revised mining plan lowered our stripping ratio in Q3 from 2.5 in 2011, to 1.65 in 2012.

Moving to oil and 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 considered full-value. We recorded the revenue and expense for these properties through the close date, September 27th.

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%, an increased natural gas volume of 6% compared to 2011 third quarter.

From a received pricing standpoint, the oil increased by 7% and natural gas declined by 28%. From a cost perspective, our O&M expenses increased by $2.5 million overthe 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.

The 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 assets sale. With the additional cash on October 31st, we redeemed $225 million of the 6.5% note, 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 EPSas adjusted and excludes special items. We implemented a number of initiatives to improve earnings after a slow start in the first quarter, and continue 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 lists our primary assumptions that we made regarding our earnings guidance. Our 2013 projected range earnings-per-share from continuing operations is $2.20 to $2.40, exclusive of any special items.

We have made assumptions about of rate case settlements, normal weather, planned availability, oil and gas prices and production rates, and other factors. Overall, we expect a slight improvement in operating income in 2012, over 2012, and notable reduction in interest expense, which contributes to the improved EPSas adjusted for 2013.

A midpoint-to-midpoint increase 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 we saw in the Colorado generation and coal mining segments.

The Williston Basin assets 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 $3.00 in the third quarter, and we have seen a little higher prices lately. Certainly encouraging, because it has a major impact on 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.

Thank you, Tony. Moving on slide 21, we have five major strategic objectives, focused primarily on being an industry leader in all we -- 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 triple-B flatfor a senior unsecured credit. On slide 22, related to operating performance, this exhibit is exceptional performance in 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 stability 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 records is fantastic.

Slide 24 talks -- relates to earnings growth. We expect strong earnings growth, driven primarily by capital spending, far in excess of our depreciation and 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 16th, 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 a 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 have added $15 million for approximate financing costs for the project. That $15 million will be impacted somewhat by our construction financing writer in Wyoming and then what we may choose to do in South Dakota, related to a similar filing.

As I mentioned earlier, we have received all permits we have (inaudible) 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 assets sale, our oil and gas properties represent a tremendous upside opportunity for shareholders.

In the oil and gas area, we are 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 and gas, our existing oil and 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, that's more than 16 times our year-end 2011 proven reserves of 133 bcf. equivalent.

Slide 29, on dividend growth, we are 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 are very proud of.

And finally, on slide 30, we are -- 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 Black Hills Corp. and Black Hills Power hills power during the month of October.

Finally, on slide 31, this is our 2012 Scorecard, we have shown you this for several years. It's really our way of holding ourselves accountable to you, our shareholders, for making excellent progress on our 2012 goals and objectives. And when we get to the next quarter, we will show you how we faired for the entire year of 2012, and also lay out our goals and objectives for 2013. That concludes our remarks today. We would be happy to entertain any questions.

Thank you, ladies and gentlemen. (Operator Instructions). Your first question comes from the line of Kevin Cole with Credit Suisse. Please proceed.

Good morning, gentlemen.

Morning Kevin.

I guess with the -- I am going to start with the 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 (inaudible). At what point would you feel more comfortable to offer some longer-term, I guess, regulated focus with the growth rate.

You know, Kevin, we have talked about that in the past. I -- I don't know. We have said that we rather than specific growth rate percentages, we lay out our capital spending forecast instead. And we have 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 capital expenditure forecast kind of speaks for itself.

And I guess if I look at the CAPEX forecast, it (inaudible) seem reasonable for me to assume that the EPS. growth should be at least the high single-digits to low digits between now is 2015.

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

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

I don't think we have any stated objective of a dividend growth rate percentage. Obviously, our 42-year track record of doing an increase is very important to us. And while we continue to spend a lot of capital, we also recognize that we have 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.

Okay, but we shouldn't expect like, like, an EPS. like reset, in growth reset, in the dividends.

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

And then, Tony, on the interest experience savings for 2013, are are you able to put any numbers around that? Or I guess give any visibility in further debt reductions that you plan to take on?

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 it's -- you would expect that kind of savings for at least nine or ten months of the year.

Okay, great, thank you, guys.

Thank you.

(Operator Instructions). Your next question comes from the line of Michael Worms with BMO. Please proceed.

Good morning Michael.

How you doing. Just a question on the Colorado Renewable Portfolio Standards. Now that you have completed the -- this is the first phase, the wind project, are there any other renewable projects that you are looking at down the road.

We don't have any specific plans to expand our renewables, least company-owned renewables right now. As you may be aware, Mike, in Colorado, there's the 30% RPS Standard, but it is also subject to a 2% rate cap, a 2% annual increase related to the addition of renewables. And where we are at now, and especially with the low price of natural gas, it appears that it would be very difficult to add additional renewables.

At 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 hundred more megawatts. It is directly inner connected with our system via our own transmission line, and so it makes logical sense if we are going to add renewables that that is a great place to do it, but right now we really can't add any more and stay underneath our rate cap.

Just for clarification, what takes precedent over what? Is it the actual 30% number? Or is it the other 2% rate cap? That dictates the next level of renewable build.

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

Got it, thank you very much.

You bet, thank you.

Your next question comes from the line of Sam Winter with Gabelli and Company and company. Please proceed.

Good morning, Tim.

Good morning, guys and congratulations and thanks for the detailed slides. 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 and gas business there, and proving that out, and how are you thinking about potential partners and just a little more color there if you could.

You know, the specific oil and gas CapEx is included in earnings guidance assumptions list, there, Tim. It has a range, but it is like $90 million to $105 million, I think is listed in there. And basically, to prove up our Mancos reserves, and we have talked about this before, or the potential there, we think we need several things to happen.

First is we want to drill at least two, maybe as many as four more wells, in each basin. Both the Pieance and the San Juan. Probably, we'll focus our efforts on the Pieance first, because the gas is richer and there's also some liquid yield there. So during this period alone, natural gas prices, 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 prove up the presence of the Mancos and the productivity of the Mancos under most of of our acreage block. And then we still have two more questions, really, to answer related to the productivity of that and what our ultimate resource potential is.

One is well design. How long should the horizontal lateral will be, how many fracture stages should be performed on each horizontal lateral. Our current wells, the three that we have drilled, have been about a 4,000 to 5,000 foot horizontal lateral with maybe 15 frack stages. There are other operators drilling wells that are 8,000 or 9,000 feet in a horizontal length, and as many as 30 plus frack stages.

So the combination of the work other operators are doing, plus the wells that we plan to drill, hopefully will get a better sense of what's the optimum well design, which answers a lot. It is per-well reserves. It also dictates your finding-and-development cost. And then finally well spacing. Our estimates here, 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. Again, those three questions, so proving up our acreage, proving up well design, and proving up well spacing. Those three things really need to be done before we ultimately know the true potential of our block.

I think that, realistically, it is 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, 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.

Very helpful. Thank you, David.

You bet.

(Operator Instructions). Your follow-up question comes from the line of Kevin Cole Credit Suisse. Please proceed.

Hi, guys. Sorry, just wanted to maybe dig a little deeper into 2013 Guidance. And so for the power and coal, I noticed that the conversation with in the Guidance was a little bit lighter than normal.

Are you expected power to be somewhat at steady state now with the Colorado project fully in service, and show 2013 should look a little bit like 2012? And then for the coal side, what should we think about for improvement off of 2012 numbers?

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. Flat to slightly down. That is how to think about power generation. Just for the property tax issue.

The second one is on coal mining, we expect continued improvements 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.

Okay, and I guess with EMP, with the production of 9.3 to10.3,

BCFE, I guess given assets the sale -- I guess my hedge numbers are a little off, can you give me some color on the first of all, of those number expectations? Do you expect a split between oil and natural gas? And for 2013, 2014, 2015, what is your hedge profile looking like.

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 what -- how much oil was related to the assets that we sold, you can get a pretty good handle on kind of what the oil and 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 assets sale on the Williston.

And we put out both our total expected production number for next year, and we have also put out what we sold through the nine months of 2012. So yeah, that's pretty much the expectation.

Okay. Then what is the hedge profile for 2014, 2015.

Hedging results will be out, including some of the revisions. We had some hedging 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.

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

It's really the sale of the Williston Basin assets and reducing the cost bay Is by $200 million we got a total of $227 million, so we took part of its gain, and that $200 million reduction in our cost basis. Which really eliminates the need for any ceiling test.

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

We don't have it in here, anyway.

Yeah.

Will it come out for EEI?

We haven't decided that yet.

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

I don't know that we have layed that out yet. Formally, I mean we have it internally. I would just mention again, that on the Prairie Generation Station, we have identified the actual cost of $222 million 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 costs during construction. So -- and we are going to go forward and talk with South Dakota to try to get the same kind of an arrangement.

So AFUDCwould no be recorded on that 60%, but in -- in fact, what we had received is we would receive revenue and income as we are constructing the asset that would offset any interest expense and it's -- it's actually better than the interest experience. Does that help?

Yeah, it does. Given that the project is located in Wyoming, is the first half, the good chunk of the in beginning fit under the [CUWIT] portion -- getting more cash returns towards the front of the project.

Well, 60% of the customer ownership essentially is going to be in Wyoming.

So that's the portion that will be covered by the writerRoughly 40% of the asset will be to serving South Dakota customers and we are still evaluating whether to file a similar writer for construction financing in South Dakota.

Thinking about the spending, should the project spend cycle look a lot like the Colorado projects, if I look at the lumpiness of the spending.

Yeah, it is going to look like a guest project. Upfront all you are doing is making progress payments on turbines and things like that until you actually start taking delivery of major components.

Okay, great, thank you.

You bet, thanks.

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

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.