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Executives

Bob Rowe - President & Chief Executive Officer

Brian Bird - Chief Financial Officer

Kendall Kliewer - Controller

Heather Grahame - General Council

Travis Meyer - Director of Investor Relations

Dan Rausch - Investor Relations

Analysts

Michael Kline - Sidoti & Co.

Brian Russo - Ladenburg Thalmann

Jonathan Reeder - Wells Fargo

Paul Ridzon - KeyBanc

Chris Ellinghaus - Williams Capital

Andrew Levi - Avon Capital

NorthWestern Corporation (NEW) Q4 2012 Earnings Conference Call February 14, 2013 2:30 PM ET

Operator

Good day everyone and welcome to the NorthWestern Energy Corporation, year-end 2012 financial results conference call. Today’s call is being recorded.

At this time I would like to turn the conference over to Mr. Dan Rausch. Please go ahead sir.

Dan Rausch

Good afternoon and welcome to NorthWestern Corporation’s financial results conference call and webcast for the quarter ended December 31, 2012. NorthWestern’s results have been released and that release is available on our website at www.northwesternwnergy.com. We also filed our 10-K after the market closed yesterday.

Joining us on the call today are Bob Rowe, President and CEO; Brian Bird, Chief Financial Officer; Kendall Kliewer, Controller; Heather Grahame, General Council; and Travis Meyer, Director of Investor Relations.

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 the forward-looking statements as a result of various factors, including those listed on our Annual Report on Form 10-K, recent and forth coming 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 today, those who are joining by teleconference will be able to ask questions. A replay of today’s call will be available beginning at 5 O’clock Eastern time today through March 14, 2013. To access the replay dial 888-203-1112 and then access code 7514599. The number again is 888-203-1112 and then the code is 7514599.

With that, I’ll turn it over to President and CEO, Bob Rowe.

Bob Rowe

Thank you Dan and thank you all for joining us this afternoon. We just finished our Board of Directors meeting, not long before this call and I was reminded once again of how our very strong Board of Directors is one of the keys to this company’s success.

Our net income and cash flow from operations improved in 2012 compared with 2011. Brian will talk about that in much more detail in just a minute. On the operations side, in August we completed the purchase of our natural gas production assets in Northern Montana’s Bear Paw Basin for approximately $20 million.

In November we received a final order approving our revenue request on the Battle Creek gas production fields and gathering system, which we acquired in 2010. In November we purchased the Spion Kop wind project, which was a turnkey project built for us in Montana and placed that into commercial operations in the fourth quarter.

Also concerning electric supply, we continued construction on a 60-megawatt peaking facility located in Aberdeen, South Dakota, which we expect to achieve commercial operation before the 2013 summer season.

Yesterday the Board of Directors increased our common stock dividend to $0.38 per share, payable on March 31, and that’s up from $0.37 per share.

And now Brian will discuss our year-end 2012 financial results in more detail.

Brian Bird

Thanks Bob. We reported net income of $98.4 million or $2.66 per fully diluted share for the year ended December 31, 2012, compared with consolidated net income of $92.6 million or $2.53 per fully diluted share for the year ended 2011.

Summing up the year there were a few primary drivers. The higher gross margin of $52.2 million, largely due to a $47.9 million pretax gain associated with a favorable arbitration decision. We also experienced higher operating expenses of $40.5 million, primarily due to a charge of approximately $24 million in the third quarter, for the impairment of substantially all of the capitalized preliminary survey and investigative costs associated with the domestic project, and higher other operating expenses of $16.5 million primarily related to property taxes and depreciation.

We didn’t see a reduction of interest expense of $1.8 million due to lower rates on debt outstanding and higher capitalization of accumulated funds used during construction on projects, and finally we had higher income tax of $8 million.

Our diluted 2012 EPS was $2.66 per share, but we look at a few items as being somewhat unique this year. Those are listed in our press release, so I won’t go through them all now, but the net result would be that our normalized EPS for the year was $2.37 per share. That is lower than the normalized 2011 fully diluted EPS of $2.41, due primarily to the fact of the FERC ALJ initial decision that related to 2012, estimated to be about $0.12 a share.

Recall that our original guidance for 2012 is a range of $2.35 to $2.50 per fully diluted share and we reduced that range after the third quarter to be in a range of $2.30 to $2.40 per share, due to the portion of the FERC ALJ decision that related to 2012. So long story short, our normalized earnings of about $2.37 per share on a fully diluted basis falls within the range of our updated guidance provided.

Now I’ll talk about our earnings outlook for 2013. For ‘13 we are estimating our ongoing adjusted fully diluted earnings per share to be in the range of $2.40 to $2.55 per share. Our primary assumptions for 2013 are also included in our press release and so I will not state those now.

I do want to mention two things not included in that guidance assumptions however; first, we expect our interest expense to remain pretty flat, 2013 compared with 2012. As a result of our QF arbitration decision discussed previously, we anticipate interest expense related to the QF liability for the full year of 2013 will be approximately $2.3 million lower than comparable expense in 2012. That benefit will be offset by higher average debt outstanding as a result of $150 million long-term debt issued in 2012. QF arbitration decision will reduce our non-cash interest for the remaining term of the agreement through 2024.

Secondly, regarding taxes, our NOL balance at the end of 2012 was approximately $255 million, and we still project that we will be able to utilize those federal NOL’s at least through 2016. Our effective tax rate in 2012 was 15.5% and our effective tax rate guidance for 2013 is between 12% and 16%. With the incremental PTC benefits of Spion Kop keeping our tax rates down. We do see upward movement in our tax rate over time, but do not see that rate going over 20% until l 2017.

Moving to the balance sheet. As of December 31, 2012 GAAP cash was about $10 million compared with $6 million at the end of the year 2011, and the company did have $174 million available from its revolving credit facility at December 31, 2012, compared with $130 million from the prior year.

Total debt at December 31, 2012 was approximately $1.2 billion. The company has a long-term debt to total capitalization ratio of approximately 55.8%. Decembers 30, 2012, and as we had consistently stated, we plan to stay within our 50% to 55% debt to total capital ratio.

We did issue $28 million from our equity driven program during 2012 and we may issue additional equity through this program to bring the total proceeds up to $100 million by the end of 2013.

With that, let me turn it back to Bob.

Bob Rowe

Thank you Brian. I’ll start by giving you a summary of the results we achieved as a result of finally resolving the qualifying facility dispute that we had going on now for, say six or seven years. The arbitration decision was in our favor. I do want to recognize Brian for leading the team that worked very hard on that for so long.

CELP is a qualifying facility in Montana, with which we have a purchase power agreement that runs through June of 2024. We’ve been in litigation with CELP since 2007 over how to determine energy and capacity rates under the purchase power agreement. On November 1, 2012, an arbitration panel drew the final award in our favor.

Based on the clarity provided by the final award, regarding rate calculation for 2006 through the remainder of the PTA, we’ve updated the calculation; our QF liability and we recorded a pretax gain of $47.9 million during the fourth quarter of 2012. And as Brian said, we anticipate interest expense related to the QF liability for the full year of 2013 will be approximately $2.3 million lower than comparable expense in 2012.

The deadline that challenged the arbitration panel’s final award past on January 30, and CELP did not challenge the final award. During 2013 we expect the Montana Public Service Commission will review our filings and issue our final orders, consistent with the arbitration panel’s final award for the years July 1, 2006 through June 30, 2012.

Now turning to the Dave Gates Generating Station allocation issue, which as you know caused us to defer $13.7 million. As we previously discussed in our financial results, a hearing was held in June of ‘12 before FERC administrative law judge to consider our proposed allocation methodology, which was challenged by interveners.

The FERC at the commissioner level is not obligated to follow any of the findings from the initial decision and can accept or reject the initial decision in whole or in part. Of course, we filed our appeal to the FERC commissioners of the ALJ’s initial decision.

If were the decision was allowed to stand, we would be earning a negative return on the FERC jurisdictional portion of the plant, even though it’s still needed. This is where I worked up a head of steam on earlier calls. It is needed to provide regulation service to FERC jurisdictional customers. It’s needed to meet FERC policy and goals for network reliability and it’s needed to provide variable energy resources integration that includes wind power generation.

So we find ourselves in a position where the two regulatory worlds really have collided, and again editorialize. The system is broken when something like that occurs. Ironically no one disagrees that the plant is and was needed; no one disagrees that the costs incurred were anything other than prudent.

The Montana Public Service Commission issued a very thoughtful fact based decision concerning the 80% of the plant under its jurisdiction. The FERC process and the initial decision from the ALJ would seek either to shift costs to state jurisdictional customers or simply to allow them to fall between the cracks. So the issue is important to us as a company and I think it’s important for larger public policy reasons as well.

We filed our brief opposing initial decision on October 22 and again, consistent with some of the larger concerns, the Montana Public Service Commission filed an excellent brief; the Montana consumer council file, Bonneville Power Administration file, and then there is notably EEI, the Edison Electric Institute, our national trade association also filed and all of the comments were either generally in support or very strongly in support of our position.

So following these briefs, the full FERC will review the entire matter and issue a binding decision. There isn’t a procedural schedule in place for commissioner level review, but generally we think it’s reasonable to expect a decision sometime within the first six to nine months of the year.

If we were forced to pursue our full appellate rights through re-hearing an appeal to the United States Court of Appeal, the procedural schedule could extend certainly into 2015. We continue to bill customers on interim rates, which have been effective since January 1, 2011 and these interim rates are of course subject to a refund plus interest pending final resolution at the FERC.

Now I’d like to discuss several of our 2012 investment projects; first, with respect to electric supply investments. As we previously discussed during the first quarter of ‘12, the Montana Public Service Commission issued an order approving our application for pre-approval to purchase the 40-megawatt wind project in Judith Basin County in Montana and that’s the Spion Kop project I mentioned.

That order included an authorized rate of return of 7.4%, which was computed using a 10% return on equity and a 5% estimated cost of debt and a capital structure of 52% debt and 48% equity. In November, we purchased that project for approximately $84 million and placed it into service.

During the fourth quarter, we also made a compliance filing to reflect actual project costs and that included an adjustment to reduce the cost of debt to 4.23%, and therefore the authorized rate of return up to 7.0%. Beginning in December of ‘12, the cost of service to the electricity generated, including a return on our investment has been included in our Montana electric supply rates.

Turning next to natural gas reserves, an opportunity we are very excited about for our customers and for the company. We recently received approval from the Montana Commission to place the Battle Creek’s natural gas assets into rate base and you recall that we purchased these proven traditional assets production field at Battle Creek and gathering system in 2010 for $12.4 million as part of an overall strategy to provide greater long term rate stability and customer value, through the addition of regulated cost based resources that are not subject to market forces.

There was no immediate rate impact associated with the filing, since the revenue was already being collected and rates through the natural gas tracker. In addition to the Battle Creek production field, in September of ‘12 we completed the purchase of natural gas production interests in Northern Montana’s Bear Paw Basin for approximately $19.5 million.

So with these two purchases, Battle Creek and Bear Paw, we now have procured about 10% of our Montana retail natural gas obligations. NorthWestern has a included the cost of service for the Bear Paw Basin properties as part of our monthly natural gas supply rate adjustments on an interim basis, and that began on December 1, 2012 and of course that’s pending NorthWestern, depending on a filing with the Montana Public Service Commission for a full review of the costs.

In the meantime, our goal in this area remains to be able to own a rate base, about 50% of our Montana natural gas needs, which will be about 10 Bcf of our 20 Bcf overall annual needs to serve our Montana retail gas customers.

Now, I’ll give you an update on our regulatory calendar. First as we discussed last quarter, we have filed with the Montana Commission a request to adjust natural gas rates by $15.7 million to account for investments in our natural gas transmission distribution and storage systems and to implement pipeline integrity and infrastructure improvements, as well as cover increased expenses.

And in our filing, we requested a capital structure of 52% debt, 48% equity and a 10.5% ROE. The return on rate base requested was 7.83%, based on a cost of debt of 5.39%. Notably, the rate of return we received on our 2009 rate case from the commission was actually higher than that, at 7.92%.

The original, I mean in that case, the original rate of return request on the ‘09 case was 8.3% with a 10.9% ROE at a cost of debt of 5.76%. A lot of numbers there, but the bottom line is we’ve been obviously successful accessing the debt market, and we’ve been successful in pulling through, I think very good overall rates of return to our customers.

Decision is due from the Montana Commission by June 30. A hearing on the case is scheduled to begin on April 16. We have also asked for an interim natural gas rate increase, pending of course a full review of the filing by the commission. Although the commission is not bound statutorily to grant interim rates, they have typically reviewed and acted on requests for interim rates after a testimony has been received. In this case a testimony was received from two parties on Friday, a large customer group and the Montana Consumer Council.

In the Montana Consumer Council testimony, they advocated reducing the ROE to 9%. They recommended a 55% to 45% capital structure, made various rate base adjustment recommendations and recommended decreasing the O&M by about $1.5 million. The net results of the Montana Consumer Council’s filing would be a revenue increase of $4.1 million. So obviously substantially lower than the requests that we had made. We’ll be filing our rebuttal testimony in mid-March.

Turning to our distribution system, over the past several quarters we’ve been discussing with you our very active implementation in Montana of our Distribution System Infrastructure Plan or DSIP, and that’s part of our commitment to maintain high level reliability and system performance and as we continue to evaluate the condition of our distribution assets. Although we are not doing anything, but the same problematic sense for providing exactly the same level of character work, South Dakota and Nebraska operations.

The primary goals for infrastructure investments are to reverse trends in aging infrastructure, maintain reliability, proactively manage safety, build necessary capacity into the system and prepare a network for the adoption of new technologies as that makes sense. We are working on various solutions and evaluating the implementation of additional technologies to prepare the overall system for good applications again as it makes sense.

You can think about this as a seven-year program in which we just concluded a two year ramp-up and are now going into five years of full production, and our distribution leadership team and our DSIP team specifically have just done a tremendous job with the management of this project.

During the year ending 2012, our deferred expenses for DSIP under our Public Service Commission Accounting Order were about $16 million. The amortization of these expenses will be about $3.1 million annually over five years beginning in ‘13. That’s in addition to the approximately $10 million expenses we planned to incur on DSIP in this year. And in addition, we are projecting about $72 million of incremental DSIP expenses and about $253 million of DSIP capital expenditures over a five-year time span, beginning this year.

Based on our current forecast, along with the Montana Commission’s approval of the accounting order that I mentioned, we believe DSIP related expenses and capital expenditures will be addressed and ultimately recovered in base rates through annual or bi-annual general rate cases.

Moving on to base load electric supply, so in Montana we obtained as you know a significant portion of our electric supply from power purchase agreements that will expire by the end of ‘14.

Over time and where it makes economic sense, we’d like to transition that power purchase agreement supply into rate base in order to provide reasonable and stable rates for our customers over the very long term, and as we stated in our bi-annual integrated resource plan filed with the Montana commission late in 2011, we are beginning analysis of the viability of building a base load natural gas plant in Montana to add service to meet our electric supply needs.

Now turning to supply investments for the South Dakota service territory, on the electric side. In 2011 we began construction of a peaking facility that we will fully own, located near Aberdeen, about 60 megawatts. This facility will provide peaking reserve margin necessary to comply with capacity reserve requirements.

With respect to the peak that we’ve incurred capital expenditures is of about $51 million year-to-date, and we expect the capital expenditures to finish the project this year, probably less than $2 million, and we expect to achieve commercial operation before this coming summer.

As we’ve been discussing with you for quite some time now, we do need to address emissions reductions at the Big Stone power plant in Northeast South Dakota and also the Neal plant in Northwest Iowa. The Big Stone and Neal 4 generation facilities are both subject to additional emission reduction requirements. We’ve been doing the planning at Big Stone for some time and we expect to begin incurring the costs for that work this year, with costs spread over three years and completion in 2016.

Neal 4 began incurring these costs in ‘11 and the work is expected to be completed this year. Our current estimate of capital expenditures related to these projects is about $119 million, and that includes about $47 million this year.

We planed to file a 2013 electric rate case with the South Dakota Public Utilities Commission, with a 2012 test year and that would include costs associated with both, emissions reduction project that have been incurred up to that point. Then in addition as part of that rate case filing, we would intend to propose environmental writers from 2013 through the end of the installation of the equipment on both of these projects and we expect to make that filing probably around mid-year.

Turning back to the transmission side of the business in Montana, as you all well know, we have put the Mountain States Transmission Intertie or MSTI annual related collector system on the shelf. We do not anticipate incurring significant additional costs in the foreseeable future related either to MSTI or to the collector system. We’ve informed both; the federal and state siteing agencies that we intend to leave our applications on file, but inactive for the foreseeable future, as we analyze our strategic options.

So accordingly we have impaired substantially all of the preliminary survey and investigative costs and gross total about $24 million associated with MSTI. We do remain in process related to the proposed upgrade to the existing Colstrip 500-kV line. That project, including construction timing is dependent on other investments, the BPA, Bonneville Power Administration has planned for the west in the interconnected system.

We are focusing our project efforts right now on working with BPA and their system plans. As of December 31, we capitalized about $1.2 million of preliminary survey and investigative costs associated with this upgrade and we expect very little additional capital spend until a decision is made by BPA to move forward.

The investment potential for the Colstrip 500-kV upgrade ranges from somewhere between $40 million and $70 million, depending on how many of the current Colstrip transmission owners decide to invest in the project.

The upgrade to this system could be completed by the end of 2016; however, again the timing will need to be coordinated with BPA’s portion of the upgrade further west. In the meantime, and this is something I’ve been emphasizing for a number of years, we continue to focus on the transmission system that we build, maintain and operate to serve our native service territories.

And we respond to requests from customers for generation and connection, and transmission service and capital expenditures for growth and reliability have been occurring. Apparently, that’s true about the gas and the electric transmission system as we continue to maintain and improve our transmission infrastructure.

On the electric side, we have several upgrades and expansion projects to our existing transmission system in process that will serve to improve reliability and capacity to respond to customer growth. We expect to spend about $70 million on these projects over the next five years. These projects are included in our maintenance CapEx that are disclosed in the 10-K, but again, they have been growing over the past several years and that is why we are highlighting it.

So in summary, before we avoid your questions, our net income and operational cash flows did improve in 2012 compared with 2011. And in addition, we made acquisitions during ‘12 on both the gas and electric supply side that address resource adequacy and more long-term price stability for our customers and also improve earnings growth for the company and our shareholders.

We remain strongly focused on strengthening the core utility operations through investments in distribution and transmission improvements, as well as the supply investments that we have discussed.

But with that, I’ll conclude this part of the call and open it up to your questions and despite what I said, we will do our best to answer them.

Question-and-Answer Session

Operator

(Operator Instructions). And we’ll go first to Michael Kline of Sidoti & Co.

Michael Kline - Sidoti & Co.

Hi. Good afternoon.

Bob Rowe

Hey Michael.

Michael Kline - Sidoti & Co.

What is your timing for your next rate case in Montana? How are you thinking about that with DSIP?

Brian Bird

We do an analysis on an annual basis to determine whether or not we need to file. Obviously right now we are in the midst of the gas case in Montana and have begun work on an electric filing in South Dakota. As you said, there are extensive investments and expenses associated with DSIP. So we certainly are going to have to be looking at that.

Michael Kline - Sidoti & Co.

Okay, is the expectation I guess that the natural gas case will be behind us in Montana, South Dakota electric rate case will be implemented as well. So then really the next Montana electric rate cases will really just be centered on DSIP and the majority of the other investments will have already been recovered and you’ll be earning on that in rate base?

Bob Rowe

Potentially, yes. Obviously, there are ongoing investments in addition to DSIP and our base capital continues to increase as well. So, all of those would be reflected in any future Montana filing.

Michael Kline - Sidoti & Co.

Okay, and last question. As it relates to the regulatory environment in Montana and the New Commission, does that slow the pace of how quickly you act on maybe natural gas acquisition or maybe another generating asset, just given the newness there and the relationship?

Bob Rowe

Not necessarily. This is, I think the first time probably since ‘92 that there have been four new commissioners out of five. They come with a lot of experience. They are working very hard and what we are trying to do is simply provide them as much information as we can across the business.

Like tomorrow morning we have an informational meeting with virtually our entire executive team and the new commission. We want them to understand as much about the business, particularly from an operations perspective as possible and we want to be truly as transparent as we can.

But in terms of slowing down the rate at which we might otherwise file, we always try to be respectful of the kind of the burden on the commission and the staff, but there’s nothing new there. I misspoke; its three of the five commissioners are new.

Michael Kline - Sidoti & Co.

Okay, great. Thank you.

Operator

And your next question comes from Brian Russo of Ladenburg Thalmann.

Brian Russo – Ladenburg Thalmann

Hey, good afternoon. Maybe you could just elaborate a little bit on the up to $100 million of equity. I see that an assumption of your 2013 guidance is fully diluted shares outstanding of $38.1 million, and it looks like it’s about up about 1 million shares from 2012. So just on a current stock price of $38.50, it looks like you had issue $38 million plus worth of stock in ‘13. Is that accurate?

Brian Bird

You have to take into consideration, that $38.1 million is an average if you will through the year in terms of total, but I’m not going to give any more guidance. I did emphasize, you might have heard I emphasized, we may issue up to a total of a 100. There is certainly no guarantee that we’ll do that. But again, we are trying to manage our capital structure to stay within the 50% to 55% debt to cap.

Brian Russo – Ladenburg Thalmann

Okay, and 55%, you are comfortable with that or do you feel more comfortable at 50%?

Brian Bird

I think everybody would feel more comfortable in terms of looking for a higher rating down at 50%, but I think in terms of maintaining our ratings and continued progress of the business, we’d see our ratings would be trending upward, even at maintaining at the 55%, just based upon continued improvement in the business.

Brian Russo – Ladenburg Thalmann

Okay. Now on the Dave Gates FERC ALJ issue, it’s about $0.12 of ongoing EPS that you guys are losing out on. What portion of that $0.12 is fuel?

Brian Bird

Yes Brian, we are checking our figures here. I think probably about $0.03 to $0.04 of that $0.12.

Brian Russo – Ladenburg Thalmann

Okay and you are going to file, if I understand correctly, the ALJ just threw the original fuel filing out, because she claimed you filed the wrong form. So are you going to re-file that and potentially recapture $0.03 to $0.04 out of the $0.12 this year?

Bob Rowe

Our first move was to file on all issues together. So put them in front of the full commission as a coherent package. We’ll see what the commission’s response is to that.

Brian Russo – Ladenburg Thalmann

Okay. So you are going to wait for the FERC to rule on it in entirety and then maybe pursue and all, and if it doesn’t go your way, then maybe pursue fuel?

Bob Rowe

At this point, that’s our thinking, yes.

Brian Russo – Ladenburg Thalmann

Okay, okay, and just to clarify, the up to $100 million, technically it’s the $100 million minus the equity issued last year, right.

Brian Bird

That’s correct. The total we would do -- would be the most we would do is 100, which already includes the 28 that’s already been issued.

Brian Russo – Ladenburg Thalmann

Okay, got you and then any more clarity or visibility on the options you have available when the purchase power agreement roll-off in ‘14? I mean we are already in February of ‘13. Obviously you can’t build something in a year to replace that contract. So is one scenario you look to acquire an asset and another scenario is you sign short-term PPAs to bridge the gap until you can develop a permit and then build a CCGT? Are those the options available?

Bob Rowe

Yes, you’re correct. The time until the next set of contracts expires is getting closer and the set of options I think really is very much as you described, looking at existing assets, continuing to some extent on the market, transitioning off of the market, and then a build option as we have said previously. The build option for a plant in Montana is the one under active consideration.

Brian Russo – Ladenburg Thalmann

When are you guys filing your next IRP?

Brian Bird

I’m pretty sure its December, end of the year.

Brian Russo – Ladenburg Thalmann

December of ‘13?

Brian Bird

Yes.

Brian Russo – Ladenburg Thalmann

Okay. Thanks a lot.

Bob Rowe

Thank you.

Operator

We’ll take our next question from Jonathan Reeder of Wells Fargo.

Jonathan Reeder – Wells Fargo

Good afternoon, gentlemen. Can you hear me?

Bob Rowe

Yes, Jonathan. Good afternoon.

Jonathan Reeder – Wells Fargo

All right, a lot of my questions actually have already been asked, but do you feel like there were any surprises in the intervener testimony filed in the gas case? It looked to me that the MCC was kind of making a lot of the same arguments that have been made in the past couple of years. Is that a fair characterization?

Bob Rowe

I think I’ll just let the testimony speak for itself. Our case that we tried to come in conservatively, obviously was driven heavily by investments and it was a good time to make the filing, given what was happening on the supply side, softening the impact and then add to that the very good overall rate of return that we were able to offer. So consumer council testimony can speak for itself. Brian disagrees?

Brian Bird

I think that’s a great answer.

Jonathan Reeder – Wells Fargo

Are you still optimistic that I mean a settlement can be achieved at this stage or do you expect it to be fully litigated?

Bob Rowe

Well, I think it’s too early to answer that of course. We just saw the testimony probably at the same time you did last Friday. We are working through it and focused right now on preparing our discovery back to the interveners and then our response testimony.

Jonathan Reeder – Wells Fargo

Okay. Do you have any reason to believe that, I mean with the new composition on the MPSC, that the tone will be any different in 2013 than it has been in recent years?

Bob Rowe

That’s a big question. What I would say is the commissioners again are taking their jobs very seriously, working hard, those who are new working hard to learn all the issues and we are sincerely looking forward to working with them.

Jonathan Reeder – Wells Fargo

Okay. And then Bob, did I understand you correctly, when you filed the environmental recovery in South Dakota, is that going to be a full blown rate case or is it just for the rider?

Bob Rowe

No, it would be a full-blown rate case. In fairness, a large part because of the investments they made in supply decades ago, we’ve been out now, our electric rates have been basically stable for three decades. So the commission I think reasonably expects to have a full look.

Jonathan Reeder – Wells Fargo

Okay, and then just kind of last question, a little clarity. So in the K you kind of gave more of a full picture of the CapEx budget than I guess you have in the past. Is there, I mean, anything to read into the fact that you only have the environmental in addition to the distribution and the maintenance or should we still look at it as kind of the potential projects that you outlined as well, could still follow-up in that period?

Brian Bird

Yes, I think the best way to answer to that Jonathan is, on the supply front those are primarily the projects associated with the environmental compliance in South Dakota and these are projects that if you remember the chart that we provide to investors, it lists out our projects. In addition to our maintenance we list out our growth projects. These capture those projects that are identified. Obviously this CapEx wouldn’t capture any, let say gas acquisitions or other supply opportunities like that, things that aren’t known at this point.

Jonathan Reeder – Wells Fargo

Okay. Alright, thank you very much.

Operator

And we’ll go now to Paul Ridzon of KeyBanc.

Paul Ridzon – KeyBanc

Good afternoon.

Bob Rowe

Hey Paul.

Paul Ridzon – KeyBanc

One of the big drivers in your earnings bridge from ‘12 to ‘13 is pension costs. Can you kind of give some background on what’s happening there, and I thought you had a pension track in Montana. How does that dynamic work into it?

Brian Bird

Yes, we have it in our pension. It’s not necessarily a pension track. We had an accounting order several years’ back when we did a major funding. I believe it was 2008 that we paid $92 million contribution in our pension fund, in order for that to be treated, to smooth out if you will from an expense standpoint, we had an accounting order to spread that out. Well, the final year of that was 2012.

So on a going forward basis what you are going to see really from a pension expense is going of to be equal to our contribution if you will, and our expectation is in the $9 million to $10 million range for pension contribution on a going forward basis and thus the big drop in pension funding.

Now, we’ve known this obviously for some period of time and so as we laid out the DSIP program, we also as you might recall got an accounting order to, if you will, capitalize the expenses in ‘11 and ‘12, associated with kind of the beginning costs of the DSIP program and start to amortize those two expense in 2013 and any incremental expense in 2013 would actually hit the books in that year.

So to partially offset this drop in pension expense, we knew that we were going to have increased expense from the DSIP perspective, and that’s how we laid this out, to try and minimize the impact on customers.

Paul Ridzon – KeyBanc

Any thought on it from another pension smoothing mechanism?

Brian Bird

Well, Paul I think from our perspective, I think because we’ve done a good job of managing our pension fund, its certainly with funding in prior years, we don’t see a big impact on pension expense on a going forward basis. So we don’t anticipate a need for a pension tracker at this time.

Paul Ridzon – KeyBanc

Great, and did you change any actuary assumptions in your pension accounting?

Brian Bird

We do indeed and we share those information in the 10-K. I would have to tell you that they are pretty conservative in terms of assumptions and we can look those up for you if you’d like to see them.

Paul Ridzon – KeyBanc

I can dig them up. Thanks.

Brian Bird

Thanks.

Operator

Your next question comes from Chris Ellinghaus of Williams Capital.

Chris Ellinghaus - Williams Capital

Hey guys, how are you?

Bob Rowe

Hey Chris.

Chris Ellinghaus - Williams Capital

Brian, what’s your normalized interpretation of the fourth quarter?

Brian Bird

Normalized interpretation in total from an earnings perspective?

Chris Ellinghaus - Williams Capital

Yes.

Brian Bird

I think we’ve done that on a full year basis. I have to look something up to try and see it on a quarterly basis. Obviously we shared in our press release on a full year basis.

On the quarter front, what we’ve effectively done, this is getting from $1.57 if you will for the quarter on reported EPS, we added back $0.06 from weather perspective. Again, we had mild weather if you will in the fourth quarter, so we added back $0.06.

We did subtract out $0.79 associated with the QF arbitration decision and we subtracted out $0.06 for our income tax adjustment, which is a benefit from the Montana NOL that you’ve seen in the prior year as well. So net-net around $0.79; excuse me, it’s minus the $0.79, down to an adjusted EPS of $0.78 a share.

Chris Ellinghaus - Williams Capital

Got you, okay. Have you done any engineering or permitting at all for your new plant for Montana?

Bob Rowe

No, not at a specific engineering level, no.

Chris Ellinghaus - Williams Capital

Okay. What do you see the lead-time from basically scratch to operation for a gas plant in Montana today?

Bob Rowe

Probably a minimum of two years.

Chris Ellinghaus - Williams Capital

Okay. Is there anything currently for sale in Montana that you know of?

Brian Bird

I think that was the question I wasn’t going to answer.

Chris Ellinghaus - Williams Capital

Okay. Well, I wasn’t going to ask you about that one specific one you don’t want to answer. I was wondering if there was anything else.

Bob Rowe

Well, there certainly has been discussion about the SME plant in Great Falls. Beyond that, no comment.

Chris Ellinghaus - Williams Capital

Okay. And Brian, as far as equity goes, is there sort of a maximum size that you can get to drill a plant to?

Brian Bird

It can be we’re to increase the size of our ESP program?

Chris Ellinghaus - Williams Capital

I’m just thinking in terms of, at 55.8% you still have the ways to go, to get into your range and then I would imagine you would like to make some progress on that at some point. So I’m just thinking, going forward what you might do with drill plan or with something else.

Brian Bird

I think basic thought process is kind of the 15% of your market cap. But Chris, I mean, from our perspective, your pointing about ways to go. We are slightly outside if you look at that 0.8, but we do feel comfortable if we can hover on the upper end of that range, the 50% to 55% that we don’t see a need to have to get to the middle of that range or the bottom of that range, we believe that we can hover around that 55%.

And I’d also say and we’ve said this at prior -- people have asked about longer terms, equity needs, public forms in the past and we made a comment that other than the projects that we’ve noted today and its difficult for you to see on an earnings call I guess, but the project we’ve identified is our green project. Those projects that are knowing and we’re moving forwarded with.

Other than what’s in the ESP program, we do not need additional equity to fund those projects. So also the maintenance, all the CapEx that you see in the 10-K, we need no additional equity to finance those capital programs, other than equity within this ESP program.

Chris Ellinghaus - Williams Capital

So Ken, would it be fair to say that the next big tipping point for equity requirements is the Montana generation?

Kendall Kliewer

If in fact we were to buy or build Montana generation that would be fair. Another thing Chris, it would be fair as depending on any size, on any gas acquisitions on the gas reserve standpoint. That could have an impact as well.

Chris Ellinghaus - Williams Capital

Okay, great. Thanks a lot guys.

Bob Rowe

Thank you.

Brian Bird

Thank you.

Operator

(Operator Instructions). And we’ll go to Andrew Levi of Avon Capital.

Andrew Levi - Avon Capital

Hi, good afternoon guys.

Bob Rowe

Hey Andy.

Andrew Levi - Avon Capital

Just back on the gas reserves, any update on kind of what the market looks like as far as stuff for sale or potential acquisitions. Any type of color you can give us on where you are on that?

Bob Rowe

Just very generally that there is a market and that we used the phrase before kicking tires and then as we’ve gotten into it, going for a test-drive. We are certainly still actively looking in the market and we think with the commission’s decision and some of the comments from the commission, that it’s a direction that is supported; we are taking that to heart.

Andrew Levi - Avon Capital

And as you hoped to have something announced before second half of the year?

Bob Rowe

Probably won’t comment on that either.

Andrew Levi - Avon Capital

Okay. Thank you very much.

Bob Rowe

Thank you.

Operator

At this time there appear to be no further questions. I’d like to turn things back over to management for any closing or additional remarks.

Bob Rowe

Thank you all for your interest in the company. They were good questions. We’ll be seeing a number of you I know over the coming several months and look forward to talking to mostly all of you next quarter.

Operator

And once again that concludes our conference. A replay of today’s call will be available starting at 4:30 p.m. Central Time today until March 16, at 4:30 p.m. To access the replay dial 888-203-1112 or for international participants 719-457-0820. You’ll use a replay pass code 7514599. Again the numbers are 888-203-1112 or 7194570820 and pass code 7514599.

Thank you, and that concludes our conference.

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