NorthWestern Energy Group Inc (NWE) 2011 Q3 法說會逐字稿

Ladies and gentlemen, thank you very much for standing by.

Welcome to today's NorthWestern Corporation third quarter 2011 financial results conference call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session with instructions given at that time. (Operator Instructions) As a reminder, today's conference is being recorded and information on accessing the replay of today's call will be given at the end of the conference.

With that, I'd like to turn the conference over to our host today, Mr. Dan Rausch. Please go ahead, sir.

Good afternoon. Welcome to NorthWestern Corporation's September 30, 2011 third quarter financial results conference call and webcast. NorthWestern's results have been released and that release is available on our website, at www.northwesternenergy. com. We also filed our Form 10-Q after the market closed yesterday.

Joining us today on the call are Bob Rowe, President and CEO, Brian Bird, Chief Financial Officer, Kendall Kliewer, Controller, and Tim Olson, Corporate Secretary. This presentation contains forward-looking statements within the meaning of the Safe Harbor provision of the Private. Securities Litigation Reform Act of 1995. These things are based upon our current expectations and speak only as of this date. 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 listed on our annual report on Form 10-K, recent and forthcoming 10-Qs, and 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 the presentation today, those who are joining us by teleconference will be able to ask questions. A replay of today's call will be available beginning five o'clock Eastern time today through November 26, 2011. To access the replay, dial 800-475-6701, access code 219704. That number again is 800-475-6701 and then access code 219704. A replay of today's webcast is also going to be available on our website.

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

Thank you, Dan.

We're hosting this call from our operations center in Mitchell, South Dakota today. That's right across the street from the Mitchell Corn Palace, which is a unique local institution. As we always do, moving our Board meetings around the service territory, we had a great discussion between the Board and local employees this morning. Our Mitchell crew has actually gone over 5 years without a lost time incident, which is a remarkable accomplishment. We also had a great community meeting last night, talking about our investments in infrastructure in the Mitchell area, It was attended by local business, economic and civic leaders, legislators, the mayor, the Public Utility Commission. And as is always the case when we come out for these Board meetings, I'm reminded just how really vibrant our service territory is.

Turning to a summary of the quarter's activity, net income increased to $14.9 million for the third quarter of 2011, compared with $14.4 million for the third quarter of 2010. Our earnings were in line with expectations. Our operating, general and administrative expenses increased when compared to the third quarter of 2010; however, they declined compared with the second quarter of 2011. And that was as expected.

Our wholesale transmission revenues continued to suffer as a result of high streamflow and hydro conditions. But again, we expected that to be the case. Income tax expense declined, due to higher repairs and bonus depreciation-related deductions. In addition, yesterday the Board of Directors declared a common stock dividend of $0.36 per share, payable on September 30 to common shareholders of record as of September 15.

Now, Brian Bird, our Chief Financial Officer will discuss our 2011 financial results in more detail. Brian?

Thanks, Bob.

As Bob said, we reported net income of $14.9 million, or diluted EPS of $0.41 per share during the third quarter of 2011, compared to net income of $14.4 million, or $0.40 a share in the third quarter of 2011 -- 2010, excuse me. Gross margin increased by approximately $11.1 million during the third quarter of 2011 compared to the same period of 2010. The primary drivers are the Dave Gates Generating Station revenues from Montana retail customers, an increase in electric volumes due primarily to warmer summer weather and to a lesser extent, customer growth, and the expiration in December 2010 of a power sales agreement related to Colstrip Unit 4. These items were offset by a reduction in transmission revenues due to a combination of hydro generation conditions and other factors that reduce demand.

Our operating, general and administrative expenses increased by approximately $7.8 million during the third quarter of 2011, compared to the same period of 2010. However, that is in line with what we expected. Most of that variance is related to reserve we recorded for a $2.3 million employee-related dispute that occurred in the third quarter of 2011, and from $2 million in insurance recoveries that decreased the third quarter of 2010 expense results. Also, we incurred an increase of about $2.1 million operating costs at our plants. About $1.2 million of that related operating costs to manage the DGGS, or the Dave Gates Generation Station plant, and we incurred about $900,000 more in plant partner operating costs at Colstrip Unit 4, Big Stone, and Neo plants, due to maintenance.

In addition, we had $1.3 million in operating expenses for customer efficiency programs that were recovered in supply trackers and thus are included in our margin increase. And finally, we had operating and maintenance costs primarily from an $800,000 write-off in an abandoned gas transmission project, due to a more cost effective solution. These increases were partially offset by timing of some of our distribution operating work done earlier in the year, along with lower labor costs due to increased capital work and expense offset, and lower administrative costs and outside services.

Other operating expense items. Property tax expense increased $2.1 million over the third quarter of 2010, due primarily to the addition of DGGS and other capital additions. And income tax expense decreased $4.1 million for the third quarter of 2011, with an effective tax rate of the 4.1%, which significantly contributed to our earnings. The income tax benefit was primarily due to higher repairs and bonus depreciation-related deductions. We recorded a $3.2 million flow-through repair deduction for the quarter, compared with a $2.3 million repair deduction in the third quarter of 2010. In addition, we were able to reduce our tax expense for flow-through on state bonus accelerated depreciation by $1.2 million for the quarter. Through the recording items I just mentioned, the year-to-date 2011 effective tax rate is approximately 13.7%. We now expect the overall tax rate for all of 2011 to be between 13% and 16%.

As a quick reminder to what we've said recently about bonus and other flow-through matters, I'd like to give you a quick overview of those items. Our state regulars mandate flow-through tax accounting on certain tax deductions. Flow-through tax accounting reduces book tax expense by these certain tax deductions, such as repairs expense, and state accelerated tax depreciation, including bonus depreciation. Such tax deductions benefit customers in future rate cases. We expect to continue to receive the benefit of the lower tax rate because of the flow-through tax accounting in our jurisdiction.

Now I'll talk about our earnings outlook for the rest of 2011. After reviewing our year-to-date results and looking to the last quarter of the year, we are modifying our estimate for fully diluted earnings per share in 2011 with a range of $2.30 to $2.40 per fully diluted share. That's a change from $2.25 to $2.40 per fully diluted share. Our year-to-date fully diluted EPS through September 30, 2011 is $1.60. Based upon results for the first 9 months of the year, we plan to back out for an adjusted earnings basis about $0.08 per share for a positive weather effect on our electric and natural gas distribution business for the first three quarters, of which $0.01 per share was related to the third quarter, and about $0.07 a share for the tax benefits related to the state NOL valuation reserve release recorded in the second quarter of 2011. Then we would add back $0.05 a share for a dispute with a former employee in the third quarter of 2011, and about $0.05 a share for lost transmission revenues related to hydro generation conditions for the second quarter, and to a smaller extent, the third quarter. As a result, our adjusted EPS through September 30, 2011 is about $1.55 per share.

For the fourth quarter 2011, we expect gross margin will be positively impacted by approximately $6 million for the remainder of 2011, as compared with the fourth quarter of 2010, due to the inclusion of the Dave Gates Generating Station in rates. A fourth quarter 2011 increase in retail volumes due to modest customer growth, as compared with the fourth quarter 2010. For the last quarter of 2011, we expect wholesale transmission revenues to be similar to the fourth quarter of 2010.

On the expense side, increase in operating, general and administrative expenses, as compared to the fourth quarter 2010, we expect an increase due primarily to the addition of DGGS, which began commercial operations in January 2011. But down slightly from the third quarter of 2011, due to the timing of employee work on capital projects, which is capitalized instead of expensed. Expect a comparable level of property and other tax expenses, depreciation expenses and other income for the fourth quarter of 2011 as compared to the third quarter of 2010 --excuse me, compared to the third quarter of 2011 levels. Excuse me. Modest increase in interest expense for the fourth quarter 2011, as compared to the second quarter and third quarter 2011levels, due to seasonal increased debt levels on our credit facility for working capital purposes, with a lag between our purchases and commodities and the receipt from our customers typical for this time of year.

And as previously mentioned, we expect our effective tax rate for 2011 to range between 13% and 16%. We also expect normal weather in the Company's electric and natural gas service territories for the remainder of 2011, and of course use fully diluted average shares of 36.5 million.

Moving on to the balance sheet, as of September 30 2011, our total let net liquidity was $192.8 million, including $6 million of cash and $186.8 million of revolving credit facility availability. Total debt at September 30, 2011 was approximately $1 billion, compared with approximately $1.1 billion at December 30, 2010. The Company has a long-term debt to total capitalization ratio of approximately 54.9% at September 30, 2011. As we note in our 10-K, we plan to maintain 50% to 55% debt to total capital ratio.

Cash provided by our operating activities totaled $211 million for the 9 months ended September 30, 2011, as compared with $188 million during the 9 months ended September 30, 2010. This increase in operating cash flows is primarily due to improvement sin the timing and collection of costs, including our supplier property taxes tractors, as well as higher net income adjusted for higher non-cash depreciation. Cash used in investing activities decreased by approximately $54 million, as compared to the first 9 months of 2010, due primarily to additions related to the DGGS project in the prior year. And finally, cash used in financing activities totaled approximately $86 million during the 9 months ended September 30, 2011, as compared with approximately $8 million during the 9 months ended September 30, 2010.

I'd like to remind investors that during the first quarter of 2011, we entered into a commercial paper program to issue up to $250 million to provide an alternative financing source to fund short-term liquidity needs at much lower costs. At September 30, 2011, we had about $113 million outstanding under that program. As you can see, our balance sheet, liquidity, and cash flows remain strong.

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

Thank you, Brian.

I'll start with a regulatory update for various filings to date, as well as regulatory activity we expect for the rest of the year. First, in our distribution operations, as I mentioned last quarter, we did receive an accounting order to start our Montana distribution system infrastructure plan, or the DSIP. We're currently projecting capital expenditures for this infrastructure investment in both gas and electric to be approximately $287 million over a 7-year time span, beginning in 2011. We received the accounting order from the MPSC in March of this year to defer and amortize incremental operating and maintenance expenses for 2011 and 2012, and those are estimated to be $16.9 million to be amortized over a 5-year period beginning in 2013. The DSIP operating expenses are in addition to our base operations, so capitalizing these expenses will not reduce the pace of our operating costs. As of September 30, we've deferred incremental expenses of approximately $2.3 million as we ramp that very exciting program up. We've spent approximately $8.5 million of DSIP-related capital expenditures, and these are not being deferred.

Based on our current forecast, along with the MPSC's recent approval of the accounting order, we are moving ahead. Indeed we will be meeting with the Commission in an informational meeting to discuss our just released technical plan on October 31. And we believe that DSIP-related costs will be recovered in rate-based or by annual general rate cases. Our estimated capital cost for DSIP for 2011 and 2012 is about $33 million. Again, this is in addition to our base maintenance capital expenditure s, estimated to be about $140 million per year over the next few years.

Now turning to the Dave Gates Generating Station, the DGGS. As you know, this plant was placed in service when it achieved commercial operation on January 1, 2011. We received orders from the Federal Energy Regulatory Commission in October of 2010 and from the MPSC in November of 2010 approving interim rates based on the estimated construction costs at that time. These rates became effective January 1, 2011, subject to refund, and replaced the former contracted costs for ancillary services. In March of 2011, we made a compliance filing with the MPSC reflecting the actual construction costs, and that will be used to conduct a cost review and establish final rates. Total project costs through September 30 were approximately $185 million. The Montana Commission has set a hearing on this matter to commence on November 9. We filed a request for recovery of rates with the FERC for our wholesale customers in April of 2010, and FERC granted interim rates, effective January 1, 2011.

We've been in settlement discussions with FERC staff and large customers and others taking service from the Dave Gates Generating Station. The primary issue is related -- at the federal level is related to cost allocation between wholesale and retail customers. The settlement discussions have not been successful to date, and FERC has established a procedural schedule, with the hearing set to commence January 23, 2012, and an initial decision anticipated by May 4, 2012. As I mentioned earlier, due to the process at FERC, we have deferred revenues at the DGGS.

Turning next to renewable energy projects in Montana, we entered into an agreement to purchase a 40 megawatt wind project in central Montana to be developed and constructed by Compass Wind LLC. This is an $86 million project known as Spion Kop, and provides a 25-year levelized cost to rate payers at approximately $54 per megawatt hour. On May 31 of this year, we filed for pre-approval with the MPSC to include this project in NorthWestern's rate base. And to be clear, the MPSC has not yet pre-approved anything related to this project. A hearing is set to begin on December 14. Construction would commence upon a favorable ruling, with commercial operation projected to begin by the end of 2012. If the Montana Commission fails to grant approval for the approval for the project on or before of April 1, 2012, then either party may terminate the agreement.

In South Dakota during the second quarter of 2011, we filed for a small rate increase related to our natural gas operations. We were requesting an increase of $4.1 million annually due to increased operation and maintenance costs, and to complete the Company's remediation of a manufactured gas plant site -- manufactured gas plant sites in South Dakota. And approximately $1.4 million of the requested increase relates to the annual estimated manufactured gas plant remediation costs. In the event that MGP costs are lower than estimated during the time period, the difference of course would be subject to refund to customers. We have entered into settlement discussions with South Dakota Public Utilities Commission staff concerning this case. In the event that no settlement occurs, the South Dakota PUC would established a procedural schedule.

Now I'll provide you an update on several additional filings over the coming months. First, with respect to natural gas reserves. In 2010, we purchased a majority interest in producing wells and a gathering system called the Battle Creek field. In the interim, the $12.4 million purchase price and the cost of natural gas produced, including a return on our investment, are included in our natural gas supply tracker. So as a result, we are already recovering our costs and earning a return on an interim basis in our natural gas tracker, pending a filing with the Montana Commission to include these cost and rates on a permanent basis. We continue prepare a filing to be made with the MPSC seeking approval to add our interest in Battle Creek and the gathering system into rates. We currently plan to make this filing most likely during the first quarter of 2012 as we focus on several important cases in front of the Commission between now and the end of the year. And we do continue to explore investments in proven natural gas reserves to be proposed for rate basing to serve our Montana natural gas customers.

Now I'll address some anticipated filings with the South Dakota Commission. As we've been discussing really for over a year now, we need to address emissions reductions at the Big Stone power plant in northeastern South Dakota. And that's to address regional haze or regionally impaired visibility caused by multiple sources over a wide area. And the plant operator there, Otter Tail Power, has recommended flue gas desulfurization for sulfur dioxide emission control and a fabric filter for particulate emission control. Although studies and evaluations are continuing, the current project cost is estimated to be approximately $490 million. We're keeping the South Dakota Commission informed of developments, as we continue our analysis. We have a 23.4% interest in Big Stone, and Big Stone is a 454 megawatt coal-fired power plants. And again, the plant operator continues to refine the engineering solution most effective to address the emissions issue. It appears that it will be late fourth quarter at the least before Otter Tail proposes a definitive plan for partner approval.

Similarly, in our South Dakota service territory, the owners of coal plant Neal Number 4 -- the plant is actually located in Northwest Iowa -- are moving forward and installing a scrubber. This will occur in the 2013 to 2015 timeframe, and would have an overall project scope similar to the Big Stone scrubber project. At Neal 4, Mid-American is the plant operator, and has experienced retrofitting some of their other plants. The planned additions at Neal, which include a scrubber, a bag house, and an activated carbon injection system, are expected to provide MACT compliance for that facility. The scrubber and bag house project is already underway at Neal. Capital expenditures are currently expected to be approximately $270 million, and are estimated to be complete by the fall of 2014. At Neal, we are only an 8.7% owner. That's about 56 megawatts of a 655 megawatt facility, so our capital portion is likely to be right around $25 million.

We anticipate filing in 2013 an electric rate case for the 2012 year for South Dakota, and that would go before the South Dakota PUC to include costs associated with both of the emissions reductions projects that I've described and costs incurred up to that point. In addition, as part of that rate case filing, we plan at this time to propose to file environmental riders under South Dakota law from 2013 to the end of the installation of equipment again for both of these projects. Do note the South Dakota PUC has previously allowed the recovery of costs for environmental improvements on a timely basis.

Turning to an update on other projects we have discussed in past quarters. In South Dakota related to electric supply, on October 14, we had a ground breaking for a peaking facility near Aberdeen. And much like the great community reception we had last night here in Mitchell, the civic leaders in Aberdeen turned out to celebrate that major investment in their area. And the Aberdeen peaker would be about a 60-megawatt facility, replacing an agreement that expires September 30, 2012. Cost of a peaker plant of that size will be right around $65 million. It's expected to go into service by the end of 2012.

In Montana, we obtained a significant portion of our electric supply, as you know, from power purchase agreements that will have expired by the end of 2014. Over time, we would like to transfer significant parts of the purchase power agreement supply into rate-based supply, in order to provide reasonable and stable rates for our customers over the much longer term. Accordingly, we're evaluating our opportunities to buy or build electric supply over the next few years.

Turning to the transmission side of the business, first in Montana. As you know, we have 3 projects in some state of proposal or development, an upgraded to our existing 500 KV Colstrip transmission system, the Collector system and the mountain States Transmission intertie for Misty. With respect to Collector and Misty, as we've noted in past discussions, we've extended our open seasons processes to at least the middle of 2012. We've discussed the reasons for the extension on prior calls. We don't really have too much to add at this point, as we continue to focus on the permitting and technical issues.

The litigation between Jefferson County and the Montana DEQ was appealed, was heard by the Montana Supreme Court in August. We expect the matter will be resolved with a Supreme Court decision by the end of this year. Though we've experienced delays with Misty, we continue to see real opportunities for the project as it advances towards a record of decision.

From a regional planning perspective, we've successfully completed the phase path rating process for Misty with the Western Electricity Coordinating Council, it's the Regional Reliability Council, WEC, and we now have phase 3 status, which effectively means from a technical perspective, the project is construction ready. This project established a path rating for Misty of 1,500 megawatts southbound and 1,150 megawatts northbound. The rating was affirmed for all of the potential alternative routes, including significantly a common corridor approach to what has been termed the northern route alternative. That's important, because that may allow Misty to more closely parallel an existing transmission line.

Moving now to the upgraded to the Colstrip 500 KV. In the second quarter of 2011, the Bonneville Power Administration issued a statement proposing 2 transmission line upgrades, 1 in Washington and then also the Colstrip upgrade in Montana. In addition, the PPA stated that it needed to coordinate with NorthWestern Energy's work on the planned Colstrip upgrade. It's assumed the other Colstrip transmission owners will participate in the upgrade along with NorthWestern. The total expected cost of the upgrade is expected to be around $125 million. NorthWestern's capital cost on the project is estimated to be approximately $38 million, again, if all partners to the transmission project were to participate in the upgrade pro rata. The upgrade to the system could be completed by the end of 2013. However, the timing will need to be coordinated with BPA's portion of the upgrade further west.

Concerning transmission opportunities in and out of South Dakota, we have reported that FERC gave the Midwestern Independent Transmission System operator, MISO, authority for a cost allocation tariff for certain projects that have been identified as having regional reliability or capacity constraint relief and other attributes and values in the MISO footprint. These are so-called multi-value, or MVP, projects. And for these MVP products, MISO will cost allocate the full revenue requirement to the entire MISO footprint. NorthWestern is not currently a MISO member. However, our South Dakota territory is embedded within the MISO geographic footprint. We continue to advance our analysis in proposing a project or projects to the MISO. And indeed, there are several 345 KV projects in or adjacent to our service territory that we could elect to -- in which we could elect to become a joint venture participant.

So in summary, our quarter really went as we had expected. To people outside the company, this may have seemed like a boring quarter. But I would like to say -- many of you have heard me say, boring is good, in many respects. Even with the unexpected charge in the third quarter, we were able to achieve our expected financial results, with a little help from a reduction in tax expense. So based on our year-to-date results and our view of the last quarter, we are comfortable tightening our guidance range to the $2.30 to $2.40 that was already mentioned, and that's per fully diluted share, for 2011. And last, but by no means least, the Board of Directors yesterday declared a common stock dividend of $0.36 per share for payment at the end of 2011.

So I will conclude our filibustering and open this up for questions.

Thank you. (Operator Instructions)

First we'll go to the line of Chris Ellinghaus with Williams Capital. Go ahead, please.

Hello, guys, how are you?

Great, Chris. Thanks.

Brian, I'm a little bit confused. I think when you were going through the guidance, you talked about a $0.05 adjustment for the reserve in the quarter. But in your table on the second page, it says that's $3.2 million, or $0.09 a share. What's the difference between the $0.05 and the $0.09?

Well, the $2 million -- you had the $2 million item in the third quarter of 2010, the insurance recovery. So that's a combination of the $2.3 million and the $2 million item from 2010.

So you are netting the two together?

Correct.

Okay. But the number we should be thinking about in terms of going forward, the quarter number was the $3.2 million?

No, I mean, if you're looking at 2011 items that we are seeing as one-time items, you should be looking at the $2.3 million. $2.3 million.

Okay. And can you run through some of the tax issues from the quarter again for me?

Yes. The two tax issues for the quarter is we had incremental flow through deductions. One for repairs, just higher repairs than we've had historically. And the second was state bonus depreciation flow-through.

Okay. So that's the 2.1?

Correct.

Okay. And, Bob, can you give us any additional color on what you guys are doing with MISO exactly?

Well, we're working with -- reasonably closely with several prospective project developers. We have not made a decision to formally join MISO, simply because of the cost. But we have a very close relationship with MISO overall, and actively discuss project opportunities with several of the entities that are MISO members.

Okay. And could these be material?

Projects that would go forward certainly could be material. We're not announcing any specific project at this time.

Okay. And can you also maybe give us a little color on the pace at which Montana has been -- I don't know what the right word is, but going forward, with some of the items that you need to get done, it seems to be painfully slow.

Well, you're referring to items at the Montana Commission?

Yes.

I wouldn't say painfully slow. I would say there's a lot of work to be done in the regulatory process, and several significant matters set for hearing at the end of the year. But in any contested case, there are multiple steps. Always quite importantly including the discovery rounds. But we're pleased to have 2 important items set for hearing here, really over the coming weeks.

Okay. Great. Thanks much.

Chris, this is Brian.

I just want to make sure we're clear on that second page. When you were talking $3.2 million, that was net income and that was made up of the $2.3 million dispute, the $2 million of insurance recovery, and the $0.9 million of just higher worker compensation claims. On a pre-tax basis, that's $5.2 million, or $3.2 on a net income. The $2.3 million I'm talking about is on a pre-tax basis. I want to make sure people on the call that's clear.

Thanks.

Thank you.

Next we'll hear from the line of Paul Ridzon with KeyBanc. Go ahead, please.

Good afternoon. Can you hear me?

Yes.

Can you give kind of a sense of your trajectory that you expect the effective tax rate to follow over the next couple of years?

As we've said, 13% to 16% this year.

Paul, I guess I would say this. We would expect our tax rate to be higher in 2012 versus 2011. And the range that we're looking at right now, it's kind of that 18% to 20%.

And then kind of beyond that, just kind of trickle back up to the 30s?

Yes. Over time, obviously, some of these items from a tax perspective change. We expect that that tax rate will continue to creep up. I will tell you, though, that the repairs tax deduction is an ongoing item. So we do not expect ourselves to get back up to a 38% type tax rate. We expect something in the 20s on a going forward basis. We'll continue to work hard to keep that down as low as we can. But we do expect it to creep up.

And then that DGGS, I heard a discussion of revenue deferrals. Does that suggest that your earnings year-to-date are understated?

I wouldn't say they're understated. We are reserving for an expectation in terms of ultimately the cost for that, and ultimately for a resolution of the case.

And you haven't disclosed what you've deferred?

No.

Understood. Thank you very much.

Thank you.

Next we'll hear from --

Paul, this is for Paul, if he's still on the phone. I mean, we disclose what we reserve. We've not disclosed what we've reserved for the dispute associated in the allocation issue.

Thank you. Next we'll hear from the line of James Bellessa with D.A. Davidson.

Good afternoon.

To clarify the guidance, I'd like to reverse engineer it. You've indicated that 9 months is $1.60. You make some adjustments and you get down to $1.55 adjusted. Your guidance for the year is $2.30 to $2.40. If I subtract out the $1.55 from the 9 months, I get implied $0.75 to $0.85 in the fourth quarter. Is that what you're saying by your guidance?

That's correct, Jim.

This former employee dispute, can you give us any color on that?

Really, we can't. It relates to a former employee, and it is a confidential matter. So we have disclosed appropriately there.

Last Friday there was a bankruptcy filing in the state of Montana by a rural electric district cooperative. Are you interested in making a purchase of something like that? Does that fit into your portfolio?

Sure. I -- we wouldn't comment on any specific investment or opportunity. I would make the statement that we first of all are monitoring the bankruptcy process at SME closely, in terms of protecting our own position. And as to resource choices, we are always interested in either building or acquiring resources that would be a good fit for our customers.

You're starting to recover on Battle Creek. But it's not finalized, if I understood the formal discussion. At some point in time, they're going to look back and say, well, did you make a good investment? And are gas prices higher or lower now than they were when you made that Battle Creek investment?

Prices are lower.

And do you fear that they might say that's not working out right? You didn't hit the bottom? And therefore, you're going to have some type of disallowance?

We've had, I think, good discussions with both the Consumer Council and with the Commission staff. And the Commission staff in particular has, I think, provided us guidance in reviewing our natural gas plans and discussion around the area of gas acquisitions.

I think the key question is over the long-term, are these assets likely to provide value to our customers? And we have seen nothing over the last -- since none of the acquisitions that would change our view there.

If you don't get a chance to dollar cost average, it's hard to get a reasonable low price, I guess, on average. So hopefully you get the approvals to go ahead and make additional investments.

The tax rate at the end of the-- the tax rate that you were assuming at the end of the second quarter in your guidance was 18% to 21%. The guidance now is 13% to 16%. Can you explain what caused the tax rate to go down for the year?

The primary driver there, Jim, was on the repairs tax deduction. It came in higher than we anticipated.

Thank you very much.

Thank you.

Next we'll hear from the line of Brian Russo with Ladenburg Thalmann. Go ahead.

Hello. Good afternoon.

Hello, Brian.

Just in terms of the original 2011 guidance, can you quantify what the transmission revenue contribution was to be on a net EPS basis? And then, fast forward to now, you know, what is that contribution, and what is the annual benefit from these tax studies relative to your initial guidance?

Wow, Brian, that's a lot. I don't really have specifically what you're asking for in front of me to answer that question.

I would say that what we've done in terms of adding back the $0.05 from the lost transmission revenues associated because of the hydro conditions, gives you an idea -- we certainly didn't expect that to occur in our original guidance. So the add back is in terms of that extreme hydro conditions that occurred. So I think that's the only real guidance I can give you on the transmission side.

On the tax side, you know, obviously, the change in our tax rate, part of our comfort in terms of our guidance is where our taxes are going to shake out for the year. No doubt.

So if we were to assume a normal hydro year in 2012, you could add back the $0.05?

I think that's a fair way to look at it, Brian. And I think the other thing I'd say is the economic impact on demands, we think, were relatively the same year-over-year and it was mainly this high hydro condition. Because we did have the same type of impacts in 2010 versus 2011 on hydro. It was mainly the biggest difference in the year was the hydro condition. So I think that's a fair assessment on your part.

Okay.

And then on just through the wind farm approval process, I know there was some intervener testimony this past month. Any insight into what the major discussion items were and what will be the major items of discussion for the Commission at this December hearing?

We didn't see anything in the intervener testimony that made us think we had run a bad process or made a bad decision. The intervener was making an argument that we would have or should have or could have done various other things, but didn't really advance those positions during the selection process. So we continue to be very comfortable with the process and the result.

Okay. Great.

And then lastly, can you just remind us what your NOL balance is? And when you expect those to run out and have these more recent repairs and state bonus tax benefit pushed it out even further?

Brian, on that, I don't know the number in terms of where we are on this quarter. At the end of 2010, we were about $432 million is the number, if I recollect correctly. Obviously, with bonus and other things, we don't anticipate a big change there. But you know, to speculate in terms of what the number would be at the end of this year, I don't know. But I will tell you and reaffirm what we said in the past, our expectation is we would continue to be a to utilize NOLs through 2015 and potentially beyond there.

Okay.

And just on load growth in Montana, what type of normalized load growth are you expecting for the full-year 2011 and what can we kind of expect as we look into 2012?

We are really looking at just about 1%, slow and steady. And that's an example of I'd rather have our situation than what a lot of folks around the country are looking at.

Thank you very much.

Thanks, Brian.

Thank you. Next we will -- pardon me. Next we'll hear from the line of Michael Klein with -- pardon me, Sidoti and Company. Go ahead, please.

Hello, guys.

Most of my questions have been asked, but just around the timing of some of the regulatory events, it seems like you pushed back your filing for Battle Creek. What was that about?

Really, it's as simple as we've got a group of people in supply and regulation who are focused on a couple of key proceedings that we've already discussed. It's important to us to get those right, in addition working on the Montana side on a number of other regulatory projects. So we want to get those items cleared off the deck, and then we'll be ready to file. And again, as we've discussed, we're already earning, so we want to get that filing, we want to get the Commission to address it, but we and the Commission as well need to focus on some of the other currently pending matters.

Sure. Okay.

And with the peaker plant, that's going to be a 2013 filing, I believe you said. So when can we expect that to go into rates? Is that going to be a second half of the year event? Or before that?

Probably a little bit early to be too specific, but that seems about right. Don't read that answer back to us though in the second half of 2013, all right?

Sure. Okay.

And lastly, just on the possibility of owning more assets or, you know, building more assets, I guess, does the contract that you guys just talked about in the press release a couple weeks ago, I believe it was a 2-year contract that you were seeking, does that have any impact on the opportunity to own more assets?

No.

No? Okay. All right. Thanks a lot.

Thank you.

Next we will go to the line of Jonathan Reeder with Wells Fargo. Go ahead, please.

Can you guys hear me?

We can.

How's it going today?

Okay. Two clarifying points, please. The South Dakota rate case for electric, did you say you expect to file that in 2013?

Yes.

But in the interim you'll be going for the environmental riders?

No. You can almost think of it as a big bang rate case on the electric side. We haven't been in for a comprehensive review in South Dakota in many, many years. And we expect we would file initially for recovery for both Big Stone and Neal as part of that case, and then ask for the riders to cover going forward expenses coming out of the case.

Okay. So whatever you spent up to that point would be included in that filing? And then for the whatever components are left for future recovery would be the rider?

Exactly.

Okay.

And then, Bob, did you say that you decided not to join MISO? Is that still an ongoing decision?

No. We -- MISO provides great value. We have not at this time joined simply because the price of membership is, at this point, a little bit tough to justify. But we work actively with the MISO itself and with the MISO members.

But you haven't ruled out completely joining it at some point down the road if you can figure out I guess a better cost approach?

Absolutely. We're very supportive of the MISO effort and continue to evaluate it.

Okay.

And then when might we get a little more clarity as far as when you can move forward with more gas purchases? I mean, if you make this filing for Battle Creek in Q1 of 2012, I guess it's my understanding unless just a great deal would come along, you probably wouldn't make another purchase until you get at least the MPSC's blessing.

I would in no way rule out attractive acquisitions between now and a Commission decision. But a Commission decision around Battle Creek would be very, very helpful in giving some -- shedding some light on the fast forward.

Okay.

And then I guess, for Brian, just seeing if I'm understanding this correctly. So the repairs tax deduction level that we've seen in 2011, it sounds like it's more than what you expected at least at the beginning of the year. When you first came out with it, I think it was 20% to 24% effective tax rate. Is it fair to say that at least in 2012, you expect a fairly similar level of this repairs tax deduction? And it's just a $0.07 NOL valuation adjustment that would be rolling off?

I would expect it to be at least at this level.

At least at this level?

Correct.

Okay. That's very helpful. Thank you.

Okay. Thank you. Sorry for the delay.

James Bellessa has a follow-up question. Go ahead, please.

Yes. The Air Force is saying that they need more elbow room around their nuclear missile sites in Montana. Does that come into play in this beyond comp wind farm?

That would be news to me. No.

Thank you.

Thank you.

Okay. Thank you. (Operator Instructions)

Thank you. We'll hear from Peter Hart with SIP. Go ahead, please.

Hello, guys. It's Peter from ZLP.

Hello, Peter.

Hello, how are you, Brian?

To complicate matters further here on taxes, I saw in the Q there was a disclosure that you guys are evaluating the use of a Safe Harbor provision for the repair, you know, costs on transmission and distribution. What is that? And what will sway your decision one way or the other?

Yes, all I'd say on that is that the IRS came out with additional language in how we should be recording repairs. It's something that we will evaluate in 2012 and could have an impact on what we record there. Our read of it thus far is positive. But we'll continue to evaluate that in 2012 to see if it applies to us.

What does that mean? Do you have the opportunity to get a greater tax deduction for stuff that should have been capitalized? Is it --

It's just an opportunity to potentially have higher deductions associated with various repairs.

Okay. And then maybe we could just talk about that at EEI. Does that make sense?

As we would publicly talk about it during our presentation, sure.

Okay. Great. Thanks very much.

Thank you. And sorry for that mispronunciation.

There are no further questions in queue at this time.

Great. Well, thank you all very much. And I know we'll see a number of you at the EEI Financial Conference. And talk to others next quarter, if not before.

Thank you very much.

And, ladies and gentlemen, this conference will be made available for replay starting at 4.00 PM Central Time today and running through the 26 of November at midnight. You may access the AT&T Executive Playback service at any time by dialing 1-800-475-6701, and entering the access code 219704. International participants will dial 320-365-3844. Those numbers once again are 1-800-475-6701, and 320-365-3844, with an access code of 219704.

And that concludes our conference today. We appreciate your participation, as well as you using AT&T Executive Teleconference. And you may now disconnect.