NorthWestern Energy Group Inc (NWE) 2012 Q4 法說會逐字稿

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.

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.northwesternenergy.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; Ken Kliewer, Controller; Heather Grahame, General Counsel; 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 our forward-looking statements as a result of various factors, including those listed on 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 today, those of us joining by teleconference will be able to ask questions. A replay of today's call will be available beginning at 5.00 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.

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 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, that's up from $0.37 per share. Now, Brian will discuss our year-end 2012 financial results in more detail.

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. We had 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 MSTI project and higher other operating expenses of $16.5 million primarily related to property taxes and depreciation. We did he 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 net 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 net related to 2012. So a 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 assumption, 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 our $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 NOLs 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 effective tax rate over time, but do not see that rate going over 20% until 2017.

Moving to the balance sheet. As of December 31, 2012, 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. And 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%, December 30, 2012, and as we have consistently stated, we plan to stay within our 50% to 55% debt to total capital ratio. We did issue $28 million from our equity [dribble] 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.

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 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 have 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 issued a final award in our favor. Based on the clarity provided by the final award regarding the rate calculation for 2006 through you the remainder of the PTA, we have updated the calculation (inaudible) liability and we have 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 to challenge the arbitration panel's final award passed 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 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've 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 Commission 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. Were the decision 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, to 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 the 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 filed, Bonneville Power Administration filed. And then, very 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 a re-hearing an appeal to the United States Court of Appeals the procedural schedule could extend, certainly, into 2015. We continue to bill customers on interim rates which have been effective since January 1 of '11, and these interim rates, of course, are subject to 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 have 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, 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 to 7%. 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, that opportunity, we're very excited about for our customers and for the Company. We received -- we recently received approval from the Montana Commission to place the Battle Creek natural gas assets into rate base. As 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 included the cost of service for the Bear Paw Basin properties as part of our monthly natural gas supply rate adjustment on an interim basis. That began on December 1 of '12 and, of course, that's pending NorthWestern -- pending our 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 and rate base about 50% of our Montana natural gas needs which would 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. 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, and in that case, the original rate of return request in the '09 case was 8.3%, with a 10.9% ROE at a cost of debt of 5.76%. 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.

A 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 intervener testimony has been received. In this case, intervener 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, and made various rate base adjustment recommendations and recommended decreasing the O&M by about $1.5 million. The net result of the Montana Consumer Council's filing would be a revenue increase of $4.1 million, so, obviously, substantially lower than the request 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're not doing it in quite the same programmatic sense, we're providing exactly the same level of care to our South Dakota and Nebraska operations. The primarily goals of our infrastructure investments are to reverse trends in aging infrastructure, maintain reliability, proactively manage safety, build necessary capacity into the system, and prepare our network for the adoption of new technologies as that makes sense. We're working on various solutions and evaluating the implementation of additional technologies to prepare the overall system for smart grid applications, again, as it makes sense. You can think about this as a seven-year program in which we've 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 a 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 of expenses we had planned to incur on DSIP in this year. And in addition, we're 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 biannual general rate cases.

Moving on to base-load electric supply, still 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 would 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. As we stated in our biannual 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 of about 60 megawatts. This facility will provide peaking reserve margin necessary to comply with capacity reserve requirements. With respect to the peaker, we have incurred capital expenditures of about $51 million year-to-date. And we expect the capital expenditures to finish the project this year to be probably less than $2 million. 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 plan 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 projects that have been incurred up to that point. And then in addition, as part of that rate case filing, we would intend to propose environmental riders 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 (MSTI) and the 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 citing 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 those total about $24 million associated with MSTI.

We do remain in process related to the proposed upgrade to the existing Colstrip 500kV line. That project, including construction timing, is dependent on other investments the BPA, Bonneville Power Administration, has planned further west in the interconnected system. We're focusing our project efforts right now on working with BPA and their system plans. As at December 31, we had 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 500kV 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 the 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. We respond to requests from customers for generation interconnection and transmission service, and capital expenditures for growth and reliability have been occurring. Parenthetically, that's true in both the gas and electric transmission system as we continue to maintain and improve our transmission infrastructure.

On the electric side, we have several upgrade 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 and are disclosed in the 10-K. But, again, they have been growing over the past several years and that is why we are highlighting them.

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 operation 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.

(Operator Instructions)

And we'll go first to Michael Klein of Sidoti & Company.

Hi. Good afternoon.

Good afternoon, Michael.

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

We do an analysis on an annual basis to determine whether or not we need to file. Obviously, right now we're 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.

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 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?

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.

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 a natural gas acquisition or maybe another generating asset, just given the newness there in the relationship?

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're working very hard and what we're trying to do is simply provide them as much information as we can across the business. In fact, 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 burden on the Commission and the staff, but that's nothing new there. I misspoke. Three of the five Commissioners are new.

Okay. Great. Thank you.

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

Hi. Good afternoon.

Hi, Brian.

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 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'd issue $38 million-plus worth of stock in '13. Is that accurate?

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 $100 million. There's certainly no guarantee that we'll do that. But, again, we're trying to manage our capital structure to stay within the 50% to 55% debt to cap.

Okay. And 55%, you're comfortable with that or do you feel more comfortable at 50%?

Well, 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 in the business, we see our ratings would be trending upward even at maintaining at the 55%, just based upon continued improvement in the business.

Okay. 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, we're checking our figures here. I think probably about $0.03 to $0.04 of that $0.12.

Okay. And you're 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 refile that and potentially recapture $0.03 to $0.04 out of the $0.12 this year?

Our first move is -- 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.

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

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

Okay. Okay. And just to clarify, the up to $100 million, technically it's the $100 million minus the debt, the equity you issued last year, right?

That's correct. The total we would do -- the most we would do is $100 million which already includes the $28 million that's already been issued.

Okay. Got you. And then just, any more clarity or visibility on the options you have available when the purchase power agreements roll off in '14? We're 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 you sign short-term PPAs to bridge the gap until you can develop permit and build a CCGT? Are those the options available?

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 describe, 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.

When do you guys file your next IRP?

December, end of the year.

December of '13?

Yes.

Okay. Thanks a lot.

Thank you.

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

Good afternoon, gentlemen. Can you hear me?

Yes, Jonathan. Good afternoon.

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

I think I'll just let the testimony speak for itself. I'll say about our case that we tried to come in conservatively. I think, obviously, it was driven heavily by investments. It was a good time to make the filing given what is 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?

I think that's a great answer.

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

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're working through it and focused right now on preparing our discovery back to the interveners and then our response testimony.

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

Boy, that's a big question. What I would say is the Commissioners, again, taking their jobs very seriously, working hard to -- those who are new, working hard to learn all the issues and we're sincerely looking forward to working with them.

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?

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

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 -- 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 fall within that period?

I think the best way to answer that, Jonathan, is in 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 gas acquisitions or other supply opportunities like that, things that aren't known at this point in time.

Okay. All right. Thank you very much.

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

Good afternoon.

Hey, Paul.

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

Yes, we have had a 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 made a $92 million contribution to 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. The final year of that was 2012.

So on a going forward basis, what you're 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. We've known this, obviously, for some period of time, and so as we had laid out the DSIP program, we also, as you might recall, got an accounting order to, if you will, amortize, or excuse me, capitalize the expenses in '11 and '12 associated with kind of the beginning costs of the DSIP program and start to amortize those to 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.

Any thought of another pension smoothing mechanism?

Well, Paul, I think from our perspective, I think because we've done a good job of managing our pension fund, 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.

Great. And did you change any actuarial assumptions in your pension accounting?

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

I can dig them up. Thanks.

Thanks.

And our next question comes from Chris Ellinghaus of Williams Capital.

Hey, guys, how are you?

Hi, Chris.

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

Normalized interpretation in total from an earnings perspective?

Yes.

I think we've done that on a full year basis. I'd 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, it's the benefit from the Montana NOL that you've seen in the prior year, as well.

Okay.

So net-net, around $0.79. Or excuse me, it's minus the $0.79, down to an adjusted EPS of $0.78 a share.

Got you. Okay. Can you -- have you done any engineering or permitting at all for a new plant for Montana?

No, not at a specific engineering level, no.

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

Probably minimum of two years.

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

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

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?

Well, there certainly has been discussion about the SME plant in Great Falls.

Okay.

Beyond that, no comment.

Okay. And, Brian, as far as equity goes, is there sort of a maximum size that you can get a [dribble] plan to?

If we were to increase the size of our ESP program?

I'm just thinking in terms of at 55.8%, you still have a 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 a dribble plan or with something else?

I think basic thought process is kind of a 15% of your market cap. But, Chris, from our perspective, your point about a ways to go, we are slightly outside, if you look at that 0.8. But we do feel comfortable if we can hover around the upper end of that range of 50% to 55%. 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 questions about longer-term equity needs at public forums in the past -- and we've made the comment that other than the projects that we've noted today, and it's difficult for you to see in an earnings call like this, but the project we've identified as our green projects, those projects that are known and we're moving forward 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.

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

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

Okay. Great. Thanks a lot, guys.

Thank you.

Thank you.

(Operator Instructions)

And we'll go to Andy Levi of Avon Capital.

Hi. Good afternoon, guys.

Hey, Andy.

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

Just very generally. There is a market and we've used the phrase before, kicking tires, and then as we've gotten into it, going for a test drive. But we're 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're taking that to heart.

And is your hope to have something announced before second half of the year?

Probably won't comment on that either.

Okay. Thank you very much.

Thank you.

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

Thank you all for your interest in the Company. Good questions. We'll be seeing a number of you, I know, over the coming several months and look forward to talking to most or all of you next quarter.

And once again, that concludes our conference. A replay of today's call will be available starting at 4.30 PM Central Time today until March 16 at 4.30 PM. To access the replay, dial 888-203-1112, or for international participants, 719-457-0820, you'll use replay pass code 7514599. Again, the numbers are 888-203-1112, or 719-457-0820, and pass code 7514599. Thank you, and that concludes our conference.