NorthWestern Energy Group Inc (NWE) 2011 Q4 法說會逐字稿

Ladies and gentlemen, thank you for standing by and welcome to the NorthWestern Corporation year-end 2011 financial results conference call. At this time, all lines are in a listen-only mode. Later there will be an opportunity for your questions and instructions will be given at that time. (Operator Instructions) And as a reminder, this conference is being recorded. I'll now turn the conference over to your host, Dan Rausch. Please go ahead, sir.

Good afternoon and welcome to NorthWestern Corporation's financial results conference call and webcast for the year ended December 31, 2011. NorthWestern's results have been released and the release is available on our website at www.northwesternenergy.com. We also filed our 10-K 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; Wayne Hitt, Tax Director; and Heather Grahame, General Counsel.

This presentation contains forward-looking statements within the meaning of the Safe Harbor Provisions of the Private Securities and 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 listed 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 the presentation, those of us joining by teleconference will be able to ask questions.

A replay of today's call will be available beginning at 5 PM Eastern Time today through March 16, 2012. To access the replay, dial 800-475-6701, access code 235153. The number again is 800-475-6701 and then code 235153. 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, and good afternoon, everyone. In 2012, we are beginning our second century of service and we're looking forward to the year. We ended our first century in 2011 with a real flurry of activity and some good, positive results. 2011, we were in the top 10 for total shareholder return in the 55 Company EEI Utility Group and we provided a total shareholder return of 29.9%.

Net income increased to $92.6 million for the year ending December 31, compared to net at 2011, compared with $77.4 million in the year ending December 31, 2010. That was a 19.6% improvement. Importantly, we had a couple of other significant achievements during 2011 that I would like to highlight.

First, we received approval from the Montana Public Service Commission, the MPSC, of an accounting order to defer and amortize certain incremental, operating and maintenance costs of up to $16.9 million for 2011 and 2012, associated with our Montana Distribution System Infrastructure Project, or DSIP. We also received approval from the South Dakota PUC to increase our South Dakota Natural Gas rates resulting in an annualized revenue increase of approximately $1.8 million on the gas side.

Related to our electric supply in Montana, we signed an asset purchase agreement and requested MPSC approval to develop a 40-megawatt wind project in central Montana at an estimated cost of approximately $86 million. And just last Tuesday, the MPSC held a work session and approved the project, but they did include a condition that would reduce our revenue requirement if a minimum performance threshold at the end of the initial three years of operation is not met; and we will talk more about that later in the call.

Also related to electric supply, we began construction on a 60-megawatt peaking facility located in Aberdeen, South Dakota, which we expect to achieve commercial operation before the 2013 summer season. Related to our debt securities, Moody's Investors Services upgraded our senior, secured debt from A3 to A2. And our senior, unsecured bank credit facility from Baa2 to Baa1.

Last, but by no means least, yesterday the Company's Board of Directors declared a common stock dividend of $0.30 per share payable on March 31, 2012, to common shareholders of record as of March 15, 2012. Now I'll turn it over to the CFO who finished off our first century for us, Brian Bird.

Thanks, Bob. As Bob said, we reported net income of $92.6 million or diluted EPS of $2.53 during the year ended 2011 compared to net income of $77.4 million or $2.14 a share for the year-ended 2010. Income improved primarily because of reduction in income tax expenses, an increase in gross margin largely driven by placing the Dave Gates Generating Station at Mill Creek into service; and that was offset primarily by increased operating expenses.

Regarding gross margin, it increased $43.1 million during the year-ended 2011 compared with '10. The primary drivers were the Dave Gates Generating Station interim rates beginning January 1, 2011. Secondly, an increase in electric and natural gas volumes driven by warmer summer weather and colder winter and spring weather. And finally an expiration in December 2010 of a power sales agreement related to Colstrip Unit 4.

These were offset by a decrease in Montana property taxes including the tracker compared with 2010, and a reduction in transmission revenues due to a combination of hydro generation conditions and other factors that reduced demand. Operating, General and Administrative expenses increased by $30.2 million during year-ended 2011 compared with 2010. This was primarily driven by insurance expenses, net of recoveries, which increased by $8.8 million during the year.

Our 2010 expenses were reduced by insurance recoveries in favorable settlements totalling $6.5 million, while our 2011 results include an increase of $2.3 million due to the dispute settlement with a former employee. Other increases, labor costs increased by $5.4 million. We had higher plant operating costs with the start-up at the Dave Gates Generation Station and scheduled maintenance at both Colstrip and Big Stone plants during the year.

We also had higher operating expenses recovering our trackers. And by the way, for 2012 we anticipate our expense increase to come primarily from labor increases and property tax increase. Depreciation expense increased by $9.1 million over 2010, as a result of increasing the investment in our business. Income tax expense decreased by $15.7 million for the year, ending 2011 with an effective tax rate of 9.8%, which significantly contributed to our earnings.

The income tax expense reduction was primarily due to higher repairs deductions and state bonus depreciation deductions which are accounted for under the flow-through method. The remaining difference relates to state NOL utilization recognized in the second quarter of 2011, and adjustments related to the implementation of a new tax software system in the fourth quarter of 2011.

We expect the overall tax rate for 2012 to be between 18% and 20%. So again, net income improved to $92.6 million for 2011. And our fully diluted EPS in 2011 was $2.53. After adjusting for items, specific just to 2011, we calculate non-GAAP EPS to be $2.41.

Related to just the fourth quarter of 2011, we had a good fourth quarter of earnings in 2011. Expenses were down compared to the third quarter of 2011 by about $4.5 million, more than offsetting the mild weather of the fourth quarter in 2011. Both operating income and pretax income increased in the fourth quarter of 2011 compared with the fourth quarter of 2010.

Now I'll talk about our earnings outlook for 2012. Our estimate for fully diluted earnings per share in 2012 is a range of $2.35 to $2.50 per fully diluted share. The major drivers of earnings from 2011 to 2012 include, first, we anticipate gross margins to add between $0.25 to $0.30 per share in 2012, due mostly to customer growth, recovery of wholesale transmission revenue, and the full-year effect of the 2011 South Dakota rate case revenue increase.

Secondly, we expect AFUDC on a couple growth projects that we are working on in 2012 to add between $0.05 and $0.07 per share in 2012. That includes both the interest capitalized and the equity portion of the AFUDC. Third, we expect Operating, General and Administrative expenses to be higher and reduce net income from $0.14 to $0.18 per share during 2012. For 2012, again we anticipate our expense increases to come primarily from labor increases and property tax increase.

Fourth, we expect income tax expense to be higher and reduce net income from $0.10 to $0.14 per share during 2012. And regarding taxes, we expect continued repairs deductions during 2012. We expect bonus depreciation to go back down to 50% in 2012. And we expect no further state NOL benefit or expense to occur in 2012. We expect no further modifications for tax purposes to occur in 2012 related to the new tax software system implementation.

And finally, we expect our effective tax rate to be between 18% to 20%. Lastly, we expect depreciation expense to be higher and reduce net income about $0.04 per share during 2012. Other primary assumptions included in the 2012 guidance are, changes I just discussed are subtracted from our adjusted 2011 non-GAAP EPS of $2.41 a share. Our fully diluted average shares outstanding will be about 37 million.

We currently expect that manufacture warranties will cover repair of the Dave Gates Generating Station. And we will make regulatory filings in the normal course of collecting supply costs through the tracker process, wherein we will propose to collect the replacement cost. However, we can't guarantee that the regulators will allow full recovery of these costs. And finally, we expect normal weather in the Company's electric and natural gas service territories for 2012.

Moving onto the balance sheet. As of December 31, 2011, cash and cash equivalents were $5.9 million compared with $6.2 million at December 31, 2010. The Company had $130 million available from its revolving credit facility at December 31, 2011 compared with $96.5 million at December 31, 2010. Total debt at December 31, 2011 was approximately $1.1 billion.

Company has a long-term debt to total capitalization ratio of approximately 55.6% at December 31, 2011; and as we know, in our 2011 10-K, we plan to maintain a 50% to 55% debt to total capital ratio. With that, let me now turn it back over to Bob.

Thank you, Brian. I'll start with a review of our regulatory calendar. During 2011, we concluded rate cases both in Montana and in South Dakota. We filed an application for pre-approval with the Montana Commission during the second quarter for the Spion Kop project to be included in regulated rate cases and electric supply resource.

Spion Kop was an $86 million project that will provide our customers in Montana with a levelized cost of approximately $54 a megawatt hour. On May 31, they filed for pre-approval with the Commission to include it in rate base. In November of 2011, we filed a joint stipulation with the Montana Consumer Counsel proposing an authorized rate of return on the project to 7.4%, which was computed using a 10% return on equity, a 5% estimated cost of debt, and a capital structure consisting of 52% debt, 48% equity.

On Tuesday, as I mentioned, the Montana Commission held a work session and approved the first- and second-year, revenue requirements as requested in the application on the project. Also in the instructions to [staff the draft in order], they included a condition that would reduced our revenue requirement if the average production was less than a certain threshold for the first three years, basically the bottom 5% of forecasted wind performance.

We believe that if the facility did meet the minimum thresholds then there would be no adjustment to revenue requirement for the fourth year and thereafter. We are encouraged by the Commission action on Tuesday; however, we are concerned that the Commission went beyond the stipulation, which had very attractive financial terms for the customers.

As I mentioned, a written order has not yet been issued; and we will evaluate our options after we've had the opportunity to review the written order. If the Commission fails to grant approval to the satisfaction of both parties on or before April 1, then our divided party may terminate the agreement. But assuming satisfactory approval by April 1, commercial operation is projected to begin by December 31.

We continue to prepare a filing with the Montana Public Service Commission seeking approval to add our interest in the Battle Creek Natural Gas field and gathering system in the rates; and we do plan to file that application by the end of the first quarter. We do not anticipate filing any general rate cases during 2012; however, we believe general rate filings will be necessary in most of our jurisdictions during 2013 based on 2012 test years.

Now I'll provide an update on our strategic initiatives to enhance service to our customers and grow our business. First, in distribution, over the past several years we have been maintaining our existing distribution infrastructure by investing more in capital expenditures than our depreciation levels. In addition, as we have discussed, our Distribution System Infrastructure Plan, or DSIP, layers on top of that again to make the system reliable and ready for the future.

As I mentioned, we received an accounting order in 2011 to start the program. We developed the technical plan detailing recommended actions and estimated costs of implementing the DSIP. The accounting order allows us to defer up to $16.9 million of expenses incurred during 2011 and 2012. This is a ramp-up period. And then amortize these expenses associated with the phase-in over the five years beginning in 2013.

As of December 31 of 2011, we've deferred incremental expenses of approximately $4.9 million and incurred approximately $15.2 million of DSIP-related, capital expenditures.

We presented the technical plan during an informational meeting at the MPSC on October 31 of '11. Had a great discussion with the Commission and staff there. Based on the technical plan, we are currently estimating incremental DSIP expenses of approximately $12 million, which will be deferred under the accounting order, and approximately $18.2 million of capital during 2012.

In addition we are projecting approximately $72 million of incremental DSIP expenses and approximately $253 million of DSIP capital expenditures over the five-year time span that begins in 2013 after the two-year ramp-up. Based on our current forecasts, along with the MPSC's approval of the accounting order, we believe DSIP-related expenses and capital expenditures will be recovered in base rates through regular, general rate cases.

Moving to our base load electric supply in Montana. We obtained a significant portion of our electric supply from power purchase agreements that will have expired by the end of 2014. Over time we would like to transfer that PPA supply into rate base in order to provide reasonable and stable rates for our customers. Accordingly, we are evaluating opportunities to buy or build electric supply over the next several years.

With respect to natural gas reserves, in 2010 we purchased a majority interest in producing wells in the gathering system at Battle Creek, as I mentioned. And in the interim, the acquisition, that $12.4 million purchase price and the cost of the natural gas produced, including a return on our investment, are included in our natural gas supply tracker rates.

And we do continue then to finalize the filing with the Montana Commission seeking approval to add our interest in the Battle Creek field and gathering system into rates, and we do currently intend to make that filing by the end of the first quarter. And we continue to explore investments in other proven natural gas reserves to be considered for rate base to serve our customers in Montana.

Now I'll turn to supply investments in our South Dakota service territory. On October 14 of 2011, we had a groundbreaking for a peaking facility near Aberdeen of about 60 megawatts. And this is to replace an agreement that expires on December 31 of '12. This facility will provide peaking reserve margin necessary to comply with our capacity reserve requirements in South Dakota.

As of December 31 of '11, we had capitalized approximately $17.1 million associated with this project; and we expect additional capital expenditures of approximately $44.4 million during '12. We expect to achieve commercial operation before the 2013 summer season.

As we've been discussing for over a year now, we do need to address emissions reductions requirements at the Big Stone power plant in northeast South Dakota; and we have a 23.4% interest in this 454-megawatt, coal-fired, Big Stone facility.

In order to address regional haze or regionally impaired visibility, caused by multiple sources over a very wide area, the plant operated, which is Otter Tail Power, has recommended flue-gas desulfurization for sulfur dioxide emission control and a fabric filter for particulate emission control.

Those studies and evaluations are continuing and the current project cost is estimated to be about $490 million, though a 23% portion of the capital expenditure would be right around $125 million. And we are keeping the South Dakota Commission informed of developments as we continue our analysis. We do expect the project to be completed in 2016.

Also on our South Dakota service territory, the owners of coal plant Neal No. 4 -- the plant is located in northwest Iowa -- are moving forward and installing a scrubber in the 2013 to 2015 timeframe, which would have an overall project scope similar to the Big Stone scrubber operation. Mid-American is the plant operator in that case and has experienced retrofitting some of their other operational plants.

The planned additions at the Neil plant, which include a scrubber, bag house, and an activated carbon injection system are expected to provide Mat compliance for that facility. The scrubber and bag house project at Neal 4 is currently underway. Capital expenditures are currently estimated to be right around $270 million. We are only an 8.7% owner or 56 megawatts of the 655-megawatt facility, so our capital portion there is likely to be right around $25 million.

We plan to file a 2013 electric rate case in South Dakota with a 2012 test year that would go before the South Dakota Commission, including costs associated with both of the emission reduction projects incurred up to that point.

In addition, as part of that rate case filing, we intend to propose to file environmental riders from 2013 going forward then to the end of the installation of the equipment on both of the projects. And the South Dakota Commission has previously allowed the recovery of costs of environmental improvements and has done so on a timely basis.

Turning to the transmission side of the business, first in Montana, and by now you're quite familiar with our three transmission projects. First, the upgrade to the existing 500 kV Colstrip Transmission System. Second, the Montana Collector System, and then third, the Mountain States Transmission Intertie, or MSTI. And I'll start with MSTI.

As we've noted in our past discussions, there have been factors causing delays on the MSTI and therefore on the Collector project. One of those delays on the MSTI front was caused by the 2010 litigation between Jefferson County, Montana and the Montana Department of Environmental Quality concerning the citing process.

In October of '11, the Montana Supreme Court reversed a District Court decision. The District Court had required the MDEQ, the Department of Environmental Quality, to delay an economic impact statement concerning MSTI. So as a result of the favorable ruling now by the State Supreme Court, the MDEQ is estimated to issue a draft EIS in the third quarter of '12.

In addition to the favorable Supreme Court ruling, there have been two other, quite positive developments. First, from a regional transmission planning perspective, we have successfully completed the entire, 3-phase, path-rating process for MSTI; and that is done through the Western Electricity Coordinating Council, or WECC, so we are now at phase-3 status with the WECC, which essentially means we are ready to begin construction from a regional transmission planning perspective.

This process established a path rating for MSTI of 1,500 megawatts southbound and 1,150 megawatts northbound on the transmission line. And the rating was affirmed for all of the potential alternative routes; and that included a so-called common corridor approach to what has been defined as the Northern Route Alternative.

This is significant because it may allow MSTI to move, to more closely parallel the existing BPA Colstrip 500 kV transmission line. So potentially, a very positive way to address some of the citing considerations.

Also, in January of '12, we signed a memorandum of understanding with the Bonneville Power Administration whereby BPA has indicated a potential interest in significant capacity on the MSTI line as an alternative source for serving their loads in Idaho.

BPA has current and future requirements to serve customers in Idaho, western Wyoming, and southern Montana. And BPA currently serves these customers through agreements with PacifiCorp, using the South Idaho Exchange Agreement and the PacifiCorp General Transfer Agreement.

Because the South Idaho Exchange Agreement will terminate in 2016, BPA is evaluating various alternatives to serve its customers affected by that termination. The open seasons on this fee are now tentatively planned to resume in late 2012 or early 2013, depending on market readiness. And obviously we're monitoring the progress on the citing front at the same time. So though we've experienced delays with MSTI, we do continue to see an opportunity and see real progress related to the project.

Turning to the proposed upgrade to the Colstrip 500 kV, in 2011 BPA, Bonneville Power Administration again, issued a statement proposing two transmission line upgrades. One in Washington, and then also the Colstrip upgrade project in Montana. In addition, BPA stated that it needed to coordinate with NorthWestern Energy's work planned on the Colstrip upgrade project. It is assumed that the other Colstrip Transmissions System owners will participate in the upgrade along with NorthWestern.

The total expected cost of the Colstrip Transmission System upgrade is anticipated to be around $125 million. Our capital cost on the project is estimated to be around $43 million; that is if all participants to the Colstrip Transmission System participate ratably in the upgrade.

There has been a delay on the Colstrip upgrade project because of slower-than-expected progress on the commercial terms of the project between the Colstrip Transmission owners and the Bonneville Power Administration's internal requirement for an environmental impact study which is expected to take two more years.

So the upgrade to the system could be completed by the end of 2016; however, the timing will need to be coordinated with BPA's portion of the upgrade further west, as I noted.

Concerning transmission opportunities in South Dakota. In the past we've stated that FERC gave the Midwest Independent Transmission System Operator, or MISO, authority for a cost allocation tariff for a certain project that had been identified as having regional reliability, capacity constraint relief, and other attributes to the regional MISO footprint.

NorthWestern isn't currently a MISO member. However, our South Dakota territory is embedded within the MISO geographic footprint, so we continue to advance our analysis in proposing a project or projects to MISO.

We have commercial relationships with transmission developers at several 345 kV projects in or adjacent to our service territory; and we could elect to become a joint venture participant in those in the future. However, any possible transmission investment opportunities from our South Dakota service territory into the MISO would be several years out at this point.

Finally I'll provide an update on the Dave Gates Generating Station shutdown that recently occurred. Basically 1 of the 3, 50-megawatt units was taken off-line in mid-January due to a vibration alarm. Inspection of the three units resulted in a decision to take all the units out of service to prevent any further damage.

The turbines, which are under warranty, were or will be removed and repaired; and we plan to resume production on each unit as the turbines In fact, we are actually optimistic that we can have one of the units up and running by the end of February. The plant is anticipated to resume full production within 90 to 180 days, barring any unforeseen circumstances.

In the meantime, we've entered into contracts with third parties for replacement regulation service; and the appropriate filings have been made with the Federal Energy Regulatory Commission for these agreements. And these agreements will enable the Company to continue to provide the necessary services to maintain reliability on our transmission system.

The incremental costs of the regulation agreements, compared to the operating costs of DGGS, are estimated to be right around $500,000 a month associated with the shutdown; and we'll address these through the normal course of business. As Brian indicated earlier, we expect that the DGGS units will be repaired under warranty by Pratt & Whitney.

So in summary, the words you always wait to hear, we are pleased with our performance in 2011, very pleased. Net income increased to $92.2 million and we received approval from the Montana Commission for an accounting order to defer and amortize certain, incremental operating and maintenance costs for 2011 and '12, associated with our Distribution System Infrastructure Project, and all of our employees in Distribution have been working incredibly hard on that project.

Also, we received approval from the South Dakota Commission to increase our South Dakota Natural Gas rates. We began construction on the 60-megawatt, peaking facility in Aberdeen, South Dakota, which we expect to achieve commercial operation before the '13 summer season.

We expect to build on this performance and to provide the same service for our customers and performance for our shareholders in 2012 and looking on into our second century. With that, I'll conclude, and open up the floor for your questions.

(Operator Instructions) Paul Ridzon, Keybanc.

Looks like, from reading your 10-K correctly, it's a pretty big CapEx year. Can you talk about financing that?

Yes, in terms of the CapEx, in terms of our ongoing maintenance CapEx to be about the same, but as you know we continue to spend capital on the Aberdeen peaking; and of course if there's a good resolution on Spion Kop, expect to be spending capital there. And all I see in terms of our financing, we'll continue to use our operating cash flow and debt financing; and if it appears that we get too far astray from our 50% to 55% desired debt to capitalization, we will consider equity financing at that time.

And what is the current lifespan on the NOLs? Just to '15 or could we get to '16 at this point?

I would say this, we say beyond 2015. I'd have to say based upon where the current outcome came in on NOLs, we'd like to say beyond that, Paul, but I'd have to say I really don't know what our plans are beyond 2015 in terms of our actual capital needs. So at this point in time, we'd like to continue just to say beyond 2015.

Great, can you quantify the potential penalty if Spion Kop doesn't hit the capacity factor targets?

We really can't speak to that with any certainty until we've actually seen the written order. The two parts to that are first of all, what is the risk of not hitting the performance threshold? And then secondly, what would the size of the penalty be? So we are eager to see an order from the Commission; and we are certainly hopeful that we will be able to go forward with the project.

And just an update on how you're currently thinking about incremental natural gas reserves?

As I mentioned, we are preparing the Battle Creek filing, and expect to have that done before the end of the quarter. I know we've talked about that for some time as we moved other important matters through the regulatory process. We are at the same time actively looking at other possible acquisitions that would make sense for our customers.

We certainly think this is a very good market to participate in. I can't really comment on any specific transactions before that, or beyond that.

And then lastly, it looks like there might be a power plant or the start of a power plant for sale in Montana? How are you thinking about that?

Well, we can't comment on any specific possibilities. You're referring there to the SME facility?

Yes.

And we are obviously actively following the bankruptcy first in order to protect our own interest as a vendor there, and we are a participant on the creditors committee.

I'm sorry, one last final, final. It sounds like Pratt & Whitney, there is no recourse for LDs on replacement power costs?

We have a standard -- and this will be my final, final, I guess too. We have a standard contract with them. Pratt & Whitney has been very, very good to work with on the warranty service, but the contract does not, on its face, cover consequences.

Thank you very much.

Brian Russo with Ladenburg Thalmann

Just a follow-up on your comments earlier about the buy or build scenario with some of the contracts rolling off in 2014. Can you just remind us the number of megawatts, the contracts that are rolling off, are for? And then at what point do you have to make a decision, not only to notify the other contract party of the termination, but then also to start building a new plant?

The shortfall of the contract's roll-off would be right around 300-or-so -- 275 megawatts. The opportunity there is to probably do a combination over time of moving toward owned resources. We filed an electric supply plan with the Montana Commission that includes modeling a variety of different resource alternatives. At some point, a gas plant looks particularly attractive under most of those scenarios, but I really would think of a transition over time that would continue to include some participation in the market, and then moving towards owned resources as well. So it is not a completely binary option. Brian?

Brian, I would just add that our electric resource plan would be a good place for you to take a look at how we address your question just specifically in terms of actual contract. It is 270 megawatts today through July '12, and it is reduced down to 200 megawatts then through mid '14.

Okay, great. The planned outage on the replacement power that you'll seek recovery of it. I guess conceptually or in theory, you should receive recovery, but how are you going to proceed? Are you just going to file it with your monthly fuel factor update or is it going to be a separate filing?

No, we have a tracker in place. Those costs will flow through the tracker and then the Commission will examine that and reconcile at the end of the year.

Okay, and then also just on the capital market's activities. In addition to your cash flows, do you plan on issuing debt this year to finance the CapEx?

Yes, in terms of debt, Brian, all I would say is this, we use our revolving credit facility, and primarily commercial paper issued with the revolving credit facility, as a backstop. And ultimately we plan on terming some of that out and take advantage of today's rates.

Okay, so I guess that would put a little bit of pressure, upward pressure, on your debt to capital target of 50% to 55%?

That 50% to 55% debt to capital that we talked about includes both short-term and long-term debt, so that issuance of debt doesn't necessarily have -- that is not an incremental amount of debt, if you will. The incremental of debt will really come from increased capital that we are spending. But terming out the evolving credit facility or taking out commercial paper with it does not impact the debt to capital calculation, because again, we do that including both short and long-term debt.

I understand, okay, and just from a rating agency perspective, if you were to temporarily have a debt to cap above that 55%, are there any risks to your current credit ratings or can you kind of utilize your letter of credit capacity for, say, another year or so, and evaluate some of these larger projects that you are considering?

No, if you might be aware, in prior years, we have been above the 55%. As a matter of fact, we were slightly above it at the end of this year. Our view is, that it is okay to be at around that level, but we don't want to get too far away from the top end of that range.

Thank you.

Michael Klein with Sidoti.

A follow-up on the RPS standard. That's a soft target, correct? So you might not necessarily be definitely fined if you don't meet that?

I don't know if I would characterize it as a soft target. There is an opportunity for waiver.

Okay, so not reaching the 50% target doesn't necessarily imply a fine?

Not necessarily. We would have to request a waiver.

Okay, and when I look at the guidance, the bridge to 2012, can you just characterize what's driving the increase in just Operating, General and Administrative expenses? Is a large part of that just increased pension and costs over there? What is driving that?

You're saying the increased from '11 to '12?

Yes, I'm sorry. Yes, '11 to '12. I apologize.

As I mentioned in the call, it is primarily labor and property taxes. We don't anticipate a significant increase in pension expense based upon how we have managed pension expenses and the accounting order we have with the Montana Commission.

Okay. Thanks a lot. That is all for me.

(Operator Instructions) We have no one else in queue, Mr. Rauch.

Great, thank you all very much. We look forward to visiting with many of you in person and others next quarter.

That concludes our call. Thanks.

Ladies and gentlemen, that does conclude our conference for today. Thank you for your participation and using AT&T executive teleconference. You may now disconnect.