NorthWestern Energy Group Inc (NWE) 2010 Q3 法說會逐字稿

Ladies and gentlemen, thank you for standing by. Welcome to the NorthWestern Corporation Third Quarter 2010 Financial Results Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session. Instructions will be given at that time.

(Operator Instructions)

As a reminder, this conference is being recorded. I would now like to turn the conference over to our host, Mr. Dan Rausch. Please, go ahead.

Good afternoon, and welcome to NorthWestern Corporation's September 30th, 2010, Quarter-End Financial Results Conference Call and Webcast. NorthWestern's results have been released, and that release is available on our website at www.northwesternenergy.com. In addition, we've also filed our 10-Q.

Joining us today on the call are Bob Rowe, President and CEO; and Brian Bird, Chief Financial Officer; Dave Gates, Vice President of Wholesale Operations; Heather Grahame, General Counsel; and Kendall Kliewer, Controller.

This presentation contains forward-looking statements within the meaning of the Safe Harbor provisions of the Private Securities Litigation Reform Act of 1995. These statements are based upon our current expectations and speak only as of this date.

Our actual results may differ materially and adversely from those expressed in our forward-looking statements as a result of various factors and uncertainties, including those in our annual report on Form 10-K, recent and forthcoming 10-Qs, recent Form 8-Ks and other filings with the SEC. We undertake no obligation to revise or publicly update our forward-looking statements for any reason.

Following this presentation, those who are joining us by teleconference will be able to ask questions. A replay of today's call will be available beginning at 5 p.m. eastern time today through November 28th.

To access the replay dial 800-475-6701 and then access code 174792. The numbers again are 800-475-6701, and then the code is 174792. A replay of today's webcast will also be available on our website.

And with that, I'll turn it over to President and CEO, Bob Rowe.

Thank you, Dan. I'll start by summarizing some recent highlights. We're very happy with our results for the third quarter. Our income before income taxes improved by approximately $9 million compared with 2009.

And do recall that the third quarter of 2009 included a $12.4 million benefit related to a tax accounting method change for repair cost deductions for 2008 and the first three quarters of 2009. Thus, our net income decreased from the third quarter of 2009 this year.

In September, we reached a stipulation with the Montana Consumer Council, or MCC, in our general rate case in Montana. If the stipulation is approved by the Commission, that would result in an overall increase in our electric rates.

We also completed the purchase of a majority interest in the Battle Creek natural gas field in Montana for $11.4 million. And finally we announced our fourth quarter dividend of $0.34 per share, which is consistent with last quarter, payable on December 30th, 2010, for shareholders of record on December 15th.

Now, I'll turn it over to Brian Bird to discuss our third quarter financial results in more detail. Brian?

Thanks, Bob. We reported diluted EPS of $0.40 a share during the third quarter of 2010 compared to $0.52 a share in the third quarter of 2009. So, our earnings decreased $0.12 per diluted share on a year-over-year basis. But, that was due primarily to the absence of a $12.4 million tax benefit we experienced in the third quarter of 2009.

On a pretax income basis, we actually increased $9 million from the third quarter of 2009. So, let me give you a quick overview of the largest drivers to our pretax income.

First, our electric volumes contributing about $2.7 million additional gross margin than in the same quarter of 2009 due primarily to warmer weather in South Dakota. We recognized approximately $1.6 million in revenues related to the Montana general rate case consistent with the terms of the proposed stipulation, which is still subject to approval by the MPSC.

Our Montana transmission capacity revenues improved during the third quarter of 2010 by about $1.3 million over the third quarter of 2009, and allowance for funds used during construction, AFUDC, benefited our earnings by about $2.4 million primarily related to the Mill Creek Generating Station between decreasing interest expense and adding to other income.

As you can tell from our press release and our 10-Q filing, there were other increases and decreases to earnings year over year, but these were the most significant drivers.

Now, let me turn our discussion over to the 2010 earnings outlook. We are reaffirming our fully diluted earnings per share for the range of $1.95 to $2.10 per fully diluted share. Major assumptions include but are not limited to the following expectations.

Our guidance excludes approximately $0.06 a share for the 2010 effect of the rate increase proposed by the stipulation, which is pending approval by the MPSC. It excludes the release of the valuation allowance against certain state NOL carry-forwards and any 2010 bonus depreciation benefit. The guidance includes the tax benefit associated with the IRS approval of the tax accounting method to deduct repairs expense.

I'd also point our fully diluted average shares outstanding of 36.5 million and always the assumption of normal weather in the Company's electric and natural gas service territories for the fourth quarter of 2010.

Now, let's move on to the balance sheet. We have total liquidity of approximately $147 million with cash of about $7 million and $140 million available from our corporate revolver.

Total debt at September 30, 2010, was slightly over $1 billion compared with $987 million at December 30, 2009. The Company has a long-term debt-to-total-capitalization ratio of approximately 56% at September 30, 2010.

And cash provided by operating activities totaled $188 million for the nine months ended September 30, 2010, as compared with $129 million during the nine months ended September 30, 2009. This increase is primarily related to a decrease in contributions to our qualified pension plans of $64.4 million in 2010 as compared with the same period in 2009.

Cash used in investing activities increased by approximately $63 million as compared with the 9 months ended September 30, 2009, due primarily to increased property, plant and equipment additions related to the Mill Creek Generating Station project and Battle Creek Field acquisition.

Cash used in financing activities totaled approximately $8 million during the 9 months ended September 30, 2010, as compared with $19 million during the same period in 2009. And during the first 9 months of 2010, the Company paid dividends of $36.1 million.

With that, let me now turn it back over to Bob.

Thank you, Brian. I'll start by saying that we've just completed a successful board meeting in Helena, Montana, which among other things meant that I got to sleep in my own bed.

In addition to the Board's formal business, we had a great meeting last night with a very large group of community leaders from the state and local and private sector and had several opportunities for good meetings with employees, both last night and this morning.

I'll start by giving you a brief on the Montana rate case. As you know, in October 2009, we filed a request with the Montana PSC for an annual electric transmission and distribution revenue increase of $15.5 million and an annual natural gas transmission storage and distribution revenue increase of $2 million.

In September, we and the Montana Consumer Council filed a joint stipulation and settlement agreement regarding the revenue requirements issues in the case. Specific terms included an increase in base electric rates of $7.7 million, a decrease in base natural gas rates of about $1 million.

The stipulation, very importantly, is transparent as to key terms. The key terms were laid out and reached after all testimony was submitted and discovery was concluded, stipulation as an authorized overall rate of return of 7.92% with an authorized rate of return on equity of 10.25%, cost of long-term debt of 5.76%, and a capital structure of 52% debt and 48% equity.

A hearing was held on the complete rate case, including the revenue requirement stipulation and other matters in September. We expect the Commission to issue a final order sometime during the fourth quarter.

We did recognize $1.6 million in revenues during the third quarter, and that was consistent with the proposed stipulation. As you know, we did receive an interim rate increase in July of this year. We've -- had deferred recognition on the associated revenues under the interim until the third quarter when we arrived at the stipulation with the Consumer Council.

Turn now to the Mill Creek Generating Station, as you know, we kicked off construction at Mill Creek in October 2009. It's a 150-megawatt natural gas-fired facility, a regulating facility, estimated to cost approximately $202 million. Construction has progressed on time, on budget.

In May of 2009, the Commission issued an order granting approval to construct the facility, pre-approval decision as we have been referring to it, and authorizing return on equity of 10.25% and a preliminary cost of debt of 6.5% with a 50-50 capital structure.

In addition, the Commission specifically determined that the $81 million associated with the turbines was prudent with the remainder of the project costs to be submitted to the Commission for review and approval once construction of the facility is complete.

Construction began in June of 2009 and is on schedule to be on line January 1 of 2011. In fact, I can report that as of today the units are synchronized with the system. So we are, again, moving ahead very well.

As of September 30th, we've capitalized approximately $161.3 million in construction work in progress related to the project. We filed a request for interim rates with the Commission in October, based on the estimated construction cost.

We submitted an interim rate request based on costs in the original pre-approval filing that updates for certain known and measurable changes. As a result, this interim edition of the Mill Creek plant is expected to add $4.12 per month to the total bill of a typical residential customer using 750 kilowatt hours per month.

The rate of return for the facility has been adjusted downwards to 8.16% from the earlier 8.63%, and this is a result of the Commission ordering the 10.25% return on equity for Mill Creek as opposed to NorthWestern's 2008 proposal of 10.75%.

The reduction of long-term debt costs also go to the reduction of long-term debt costs from 6.5% in the original pre-approval filing to our new actual long-term debt cost of 6.07%.

Also concerning Mill Creek, on October 15th the FERC issued an order authorizing us to put our file tariffs in place as of January 1st, 2011, subject to refund and then set the case for hearing. So, these rates are expected to be effective beginning January 1, 2011, and would replace the current contracted costs that we're paying for ancillary services.

Now, I'll turn to the transmission side of the business. The three transmission projects we have proposed are, of course, an upgrade to the existing 500-kV coal-strip transmission system, the Montana Collector System and, third, the Mountain States Transmission Intertie, or MSTI.

As we mentioned at the end of the second quarter, we've extended our open season process related to the Collector System and MSTI. And the reasons for the extension can be summarized, first, the MSTI siting delays. We'd anticipated having a draft EIS and a preferred route by this time.

Due to the court challenge to the siting process, there have been delays in the agencies releasing the draft EIS. And to provide indicative tariffs to prospective customers, we need to know the cost of the facility, and that is heavily dependent on knowing a well-defined route.

Second, of course, general economic conditions and the slowdown and tightening of credit have combined to make it more difficult for generation developers to make long-term commitments. And it's, again, something we need to have in order to keep the projects risk-manageable.

Third factor, market confusion, and this is particularly associated with the California market and really making it difficult for generators to understand the terms of access to that large market and then fourth, the uncertainty around potential federal legislation, whether or not for example there might be a federal RPS.

So, this additional certainty has caused some hesitation by potential shippers and, for all of these reasons, we've extended the informational portion of the open season until we've all achieved the necessary clarity on these and other issues that will allow potential shippers to make the needed commitments.

During that time, we've continued to work very closely with other parties around the western United States to -- again, to support the appropriate development of the market and necessary transmission.

In the meantime, we're moving forward with the coal-strip upgrade project and design and siting of what we call the [North Electroline] and the completion of the MSTI siting process so that the process -- such so that we are -- we'll be ready to start construction when we anticipate having long-term contracts in place.

A quick update on the coal-strip 500-kV upgrade, current areas of focus are the coal-strip transmission agreement and the Montana intertie agreement along with various technical studies.

The transmission customers very much like to see the Montana Intertie rolled into the Bonneville Power Authority, or BPA, transmission network during BPA's rate case, which starts this year and will conclude in 2011.

We're making progress with the other coal-strip transmission owners and anticipate filing necessary amendments to the existing agreements later this year. It's also anticipated that the remaining study work will be completed by the end of the year.

Our capital cost for the project is estimated to be about $38 million, the total project cost of around $125 million and, as I've said previously, we would take the pro rata share if any of [coaster] partners who might decline to participate in the upgrade.

So, commencement of construction is still planned for 2011 or as soon as the study work can be complete. Then, the upgrade of the system would be completed sometime in the 2013 timeframe.

In addition, I'd like to discuss some of our supply needs in the next few years. First, I'll turn to the challenges of emissions reductions that may be required in South Dakota, again, something we discussed on the last call.

The Clean Air Visibility Rule was issued by the EPA in September of 2005 to require certain electric generating units to achieve emissions reductions from designated sources that are deemed to contribute to visibility impairment in Class I air quality areas.

We had a 23.4% interest in Big Stone, and Big Stone is a 454-megawatt coal-fired power plant located in northeastern South Dakota. The estimated capital expenditures for the best available retrofit technology, BART, based on the Department of Environmental and Natural Resources' proposal are now in the range of $500 million to $550 million for Big Stone.

With AFUDC and overheads, our share would be in the range of $130 million to $150 million, and these numbers have increased from the original estimate but should still be considered preliminary. The project engineer, Sargent and Lundy, will continue to refine the estimates as additional engineering is completed.

Any potential improvements -- or any improvements need to be installed and operated as expeditiously as practical but no later than five years from the EPA's approval of the South Dakota Regional Haze State Implementation Plan, and that is expected no later than January 15th of 2011.

If the emission reduction technology is required, we'll seek to recover these costs through the ratemaking process, and the South Dakota Public Utilities Commission has allowed recovery on a timely basis of the costs of previous environmental improvements.

Given the high cost of the emissions reduction equipment that -- we are reviewing alternatives in order to assure the most appropriate solution is identified.

Similarly in our South Dakota service territory, the owners of coal plant Neal Unit Number 4 in northwest Iowa are investigating installing a scrubber in the 2013 to 2015 timeframe, and the overall project scope would be similar to the Big Stone scrubber.

Preliminary cost estimates are being developed now. The permitting and request for proposal process are in the early stages of development. Capital expenditures are currently estimated to be approximately $220 million. We are only an 8.6% owner, or 55 megawatts, of this 655-megwatt facility, so our capital portion is likely to be around $20 million for this project.

Also in South Dakota concerning electric supply, we've mentioned previously that we're doing preliminary engineering work for a peaking facility to be located near Aberdeen. It would be about 60 megawatts and is anticipated to be in service in 2012.

Related to Montana electric supply, last month we entered into two five-year contracts derived from a competitive solicitation for on-peak power at a price below $50 a megawatt hour.

We secured two 25-megawatt, five-year trenches of heavy load hour supply agreements with delivery beginning in July of 2012, and we were pleased to lock in this level of pricing for our customers until 2017.

Moving to renewable supply, for electric supply in Montana we have requests for information to add up to 75 megawatts of renewable power. And we're looking for cost-effective renewable energy to help us meeting -- meet customer demand and diversify our resource portfolio to include more renewables.

We'd prefer to purchase the project outright but are certainly looking at other options in well -- as well, including equity interests and long-term power purchase agreements. And we are actively negotiating with a short list of suppliers now. We anticipate renewable projects to total, again, approximately 50 to 75 megawatts and come on line in late 2011 or 2012.

New developments concerning natural gas reserves, we're recently purchased a majority interest in producing wells and a gathering system called Battle Creek Field.

Net proven developed producing reserves purchased are estimated to be 7.6 billion cubic feet Bcf with annual net production attributable to the purchase, currently at approximately 0.5 Bcf, and that would be about 2.5% of our current annual consumption in Montana.

That field was in our existing -- it is in our service territory. It's near Havre, Montana, and it's connected to our existing natural gas system. Acquiring this well-defined, established, producing field is consistent with our low-risk profile by staying away from the exploration side of the business.

This field currently serves our natural gas customers under what is -- would have been a soon-to-expire purchase agreement. Under the terms of the agreement, NorthWestern paid the seller $11.4 million cash for the majority interest in the Battle Creek Field assets, and that includes the gathering system.

In 2011, or during the next general natural gas rate case, we plan to prepare a filing with the Montana Commission seeking approval to add our interest in the Battle Creek Field and the gathering system into our regulated rate base.

In the interim, the cost of the natural gas produced, including a return on our investment, will be included in our natural gas supply tracker, ending completion of the filing with the Montana Commission.

[Current] concerning our core distribution business, we have been investing in CapEx in excess of current depreciation each year since 2002. We plan to invest about $124 million in the core distribution and transmission business in 2010. And that's up from $109 million in 2009.

We are, among other things, investing in more automation, outage prevention and monitoring the Toronto system. We are also part of a regional working group that will be evaluating various smart grid applications over the next several years in order to better understand how we can and should ultimately deploy this technology in a cost effective way to the customers in our service [to occurring].

As we watching smart grid development around the country, I think we are ever more convinced that we are taking a sound and prudent approach to smart grid and new technology.

We plan to test the operational efficiencies and customer service enhancements that may be gained by the insulation of technology to enhance communication between the utility and the meter. We are focusing our work in a relatively urban area in Helena and also a very rural part of our distribution network as well.

So, in summary, we're happy with our results for the first nine months. Our financial results are, for the year, are on target. We look forward to completing the Montana rate case by the end of the year, as I'm sure are you.

We have completed a purchase of the majority interest in the Battle Creek Field, again, for $11.4 million. Our Mill Creek project is nearing completion of the construction phase, and additional generation investment opportunities are in development. Finally, we announced our first quarter dividend at $0.34 per share.

With that, I'd now like to open the call and look forward to your questions.

(Operator Instructions). And our first question is from Paul Ridzon from KeyBanc. Please go ahead.

Good afternoon. How are you?

Hey, Paul.

So you're going to have new Montana rates January 1, Mill Creek gets in rates January 1 and then Battle Creek will once you file your next [JAS] case. So that should maybe be late '11. Is that the right way to think about it?

You're right on the first two. Starting on November 1, Battle Creek will be flowing through the tracker. And our return on that investment will be part of that cost going through the tracker.

Okay. So invest November of --

This year.

This year.

Okay. Okay, thank you.

Thank you.

And our next question is from Ryan Rosenthal from Sidoti & Company. Please go ahead.

Good afternoon, everybody.

Hey, Ryan.

My first question is regarding the South Dakota peaking facility. And I was curious where you are in the regulatory process and what steps we should look forward in order to be in place by 2012.

Sure. There isn't a pre-approval process in South Dakota. So that will be more of the traditional approach. What we do intend to do over the next several months is meet formally with the South Dakota Commission to go over many of our plans in detail. But there isn't analog to the pre-approval process we used in Montana for Mill Creek.

Okay. Then if I understand correctly, you essentially build the facility ahead of a filing and then request there be expenditure is added to your rate base afterwards.

Essentially, yes.

Okay. And then concerning the gas reserves, I understand you purchased 2.5% of your annualized capacity needs for Montana. Could you discuss the opportunity to purchase additional reserves and timing that we should think of there as well?

Sure. This was a relatively small acquisition that does a number of things for us. First, it gets us back into rate-based natural gas. It gives some hands-on experience. It will give us an opportunity to take this particular resource through the regulatory process and get greater clarity around any regulatory issues and expectations.

We continue to actively look at the gas market. And they're exploring, for example, other incremental purchases of, generally, similar size. We had initially been fairly broad in what we were looking for. But we really focused in on gas properties that are in or adjacent to our existing facilities and that have reasonably long asset lives.

Okay. And considering the rate case will be necessary to add it into your rates, would you likely wait to make any larger purchases until that's decided? Or is it -- is there potential you could, if you see something attractive, purchase that more quickly?

Never say never, of course. But our focus really is on taking this acquisition and, again, potentially other smaller acquisitions through the regulatory process, get a degree of comfort there and then continue to look out.

But, again, the Commission and policy makers in Montana have been very supportive of moving back towards vertical integration on the natural gas side as well.

Okay, great. And then just one final question concerning the renewable generation and your opportunity to potentially purchase some of those facilities and add them to your rate base as well; could you provide us a little more insight, perhaps, into your discussions with the Commission and the [thick] feeling that you have currently on the potential to add those to the rate base versus [PTA] grants?

Sure. Well, again, at a high level, the Commission and, for that matter, again, our policy makers have supported moving over time towards the stability that owned rate-based resources provide. And there is strong policy direction in favor of a diverse portfolio of resources.

What we are focused on in the next year is a series of several relatively small projects and then doing the analysis that would support additional larger projects going forward.

Great. Thanks for your time, Bob.

Next we have Brian Russo from Ladenburg Thalmann. Please go ahead.

Hi. Good afternoon.

Hey, Brian.

Hey, just to clarify on the South Dakota peaker plant, it's to replace a contract with Mid-Am that's expiring, correct?

Essentially, yes.

So it -- I mean, is there kind of like a deadline as to when this plant needs to be up and running to fill in the void for that contract expiration?

Yes, mid year in 2013.

Okay, mid '13. So it's -- so there's enough time to develop this project, feel comfortable with South Dakota regulation approving this and having it commercially available in mid '13.

Well said.

Okay, and well you can get AFUDC on that, right?

Yes.

Okay. Thank you very much.

Thank you.

(Operator Instructions). Our next question is from Chris Ellinghaus from Wellington Shields. Please go ahead.

Hey, guys. Congratulations on this quarter.

Thank you.

Thank you, Chris.

From a tough critic.

Oh, yes. I'm a tough critic. It looks like you had about $2 million of pre-tax insurance recoveries in the quarter. Is that right?

We did, indeed. It's -- it was a settlement, actually, a (inaudible) issue occurred during the quarter.

Okay. Were there any other unusual items in the quarter? I didn't see much.

No, not that I would deem as unusual, Chris.

Okay. Can you just talk about your -- what you see as headwinds in the fourth quarter? You've already made, by my calculation, [$214 million] in the last 12 months. And what kind of things are in the fourth quarter that might lead us to more like your guidance range?

Brian is grabbing for the microphone here.

Hey, Chris. On that score, I mean, you may have been watching October. It's been a very mild October. Our assumptions for the quarter is normal weather. But we already know to an extent that October is going to be pretty mild. We haven't determined what the financial impact of that is yet, but just a bit of caution, if you will, looking at the quarter. We see October's results based upon weather as a headwind.

Okay. And then last year was actually a pretty decent quarter for weather if I recall correctly.

Yes, it was.

Okay. And -- but you should have some benefit for some absence of some serious maintenance outage last year in the fourth quarter and also probably a nice step down related to the repairs deduction as offsetting issues.

That's correct. If you're looking at a quarter-over-quarter basis, you know our guidance now is based upon our view for the year, that kind of comparison over year-over-year basis.

Okay. And, lastly, as far as excluding from the guidance, I think you said $0.06 related to the Montana case. How are you calculating that $0.06 differential that you're excluding?

I believe that is the third quarter component. That's the third quarter component only. It's third and fourth quarter. It's $1.6 million for the third quarter. And in the Q, we said we'd get somewhere around $2 million that we expect for the fourth quarter. So it's the two of those combined and then divide by the shares outstanding.

Okay. Okay, thanks a lot. See you later.

Your next question is from Jonathan Reeder with Wells Fargo. Please go ahead.

Good afternoon, gentlemen. One line kind of jumped out at me in release in the liquidity section. You talk about an increase in deposits received for transmission and interconnection request. Can you expand upon that?

Sure. We received some deposits for transmission reservations looking at Montana westbound from a couple of parties. And those have to be booked properly. But there's some larger players in Montana that are taking some actions.

Is that wind development that you're referring to?

It's renewable development, yes.

Okay. So, I mean, realistically, we could say that bodes well for the collector project as well as potentially MSTI.

Well, certainly, having some deposits is a positive step.

Okay. And then --

Place from -- it's a long ways from having a solid project, but it's certainly positive.

Right. And then you're kind of talking about the four headwinds on getting the commitments from MSTI. What kind of timeframe are we looking at getting clarity? Do you think your end is realistic? I mean, will the midterm elections clear up some of the log dam in California? What sort of timing should we be looking at?

I think probably the key gating factor will be the judicial action around citing in Montana. And, again, we really need clarity there in order to get certainty around a route that will allow us to come in with a cost estimate. So I think that's probably what I would focus on as much as anything at this point.

Okay. And when is the citing supposed to be wrapped up?

Well the -- in Montana, there's the district court decision. It is likely that that will go to the State Supreme Court. In Montana, there's not a heavy backlog at the State Supreme Court. And appeals are directly written at intermediate appellate court. But, still, that pushes a decision out sometime unless there is during the interim some kind of collateral resolution through negotiations or otherwise.

So when would it be that the Supreme Court (inaudible). I mean, are we -- to me, that sounds like a long process. But I'm not familiar with it.

It would be realistically sometime next year.

Okay. All right, thank you.

Our next question is from Lori Johnstone from Pacific Life. Please go ahead.

Hi, thanks. I just wanted to ask about the big stone coal fire plant and your -- the environmental cost there. Is there a chance that -- maybe what's the order there? It sounds like the costs are going up.

Is there a chance that you wouldn't be allowed to recover the costs. Or, not a given, but is it fairly likely that to the extent you incur them? Or is there a point where you say well, it's just too much? Again, I'm trying to get a sense of how risky that investment is for you.

I guess there are probably two parts to your question. And one part is cost recovery. And the second part is are we considering other alternatives. Is that --?

Yes.

Okay. Yes, there is a fairly clear cost recovery mechanism about go to Commission. Obviously, the size of this kind of an investment is significant, is bigger than the processes as been used for previously. But there is a clear path.

Secondly, we and the joint owners certainly will be considering a range of alternatives. This is a necessary resource. And, again, we have not discussed with the other owners specific alternatives. But, in a broad sense, if you look at what other parties are considering, that would be remediation, repowering or some kind of an alternative facility.

And, at this point, we're really focusing on the costs and strategies for compliance. But as we get more clarity on those costs, it's easier to also do a comparison with alternatives.

Okay, thanks. And then just maybe, overall, in your larger region -- I know wholesale's not huge for you, but maybe to the extent it would affect it at all -- do you anticipate other coal facilities having to close down because the costs of remediation are just too high?

We don't have --

I know not your --

Sure.

Plant, but.

Yes, I take the question not to be to our facilities, but --

Right.

Others in the area. We don't have any basis to speculate. But there are certainly analysts who are writing about that possibility in the Midwest, generally. And beyond what others who are writing about and thinking about the area, I have to say I don't think we have anything more to add.

Okay, thanks.

(Operator Instructions). Our next question is from James Bellessa from D.A. Davidson. Please go ahead.

Hey, guys. You've actually got [Michael Dates] filling in for Jim today. A couple of questions for you; we were curious about why the decision was made to exclude the interim rate release boost from your guidance.

Michael, it's Brian. The reason we did that is just from a comparison, apples-to-apples comparison. From the beginning of the year, we provided that guidance. We made it very clear at that point in time we had no idea of an outcome on a rate case. And so we excluded guidance from that. And just for comparison purposes to that guidance, we haven't excluded it.

And, also, I'd add that there hasn't been a decision where our booking interim rates. Until we have a final decision on that, we felt it's prudent to exclude that.

Okay, fair enough. One other nitpicky kind of question is, in your guidance, you have the assumption here that you'll have the average shares of 36.5 million for the full year. You've been at 36.2 million for the first nine months. And to get at 36.5 million for the full year, I'd have to assume that your share account goes up by like 0.5 million shares in the fourth quarter.

I think, Michael, we want to make sure it needs to be clear one of us is speaking basic and one is speaking fully diluted in terms of that analysis I think is the difference.

All right. That could be it. Thanks, guys.

And we have no further questions at this time.

Good. Well thank you all very much. I expect we'll see the number of you next week and visit with the rest of you next quarter.

All right, Miller. We're done with our remarks. So you can give the replay instructions.

Thank you, ladies and gentlemen. This conference will be available for replay after 5.00 p.m. today through midnight on November 28, 2010. You may access the AT&T executive replay system at any time by dialing 1-800-475-6701 and entering the access code 174792.

International participants dial 320-365-3844. Those numbers again are 1-800-475-6701 and 320-365-3844, access code 174792.

That does conclude our conference for today. Thank you for your participation and for using AT&T Executive TeleConference. You may now disconnect.